Fracturing System and Method for an Underground Formation Using Natural Gas and an Inert Purging Fluid

ABSTRACT

A method for fracturing a downhole formation, includes: preparing an energized fracturing fluid including mixing gaseous natural gas and a fracturing base fluid in a mixer; injecting the energized fracturing fluid through a wellhead and into a well; and continuing to inject the energized fracturing fluid until the formation is fractured. An apparatus for generating an energized fracturing fluid for use to fracture a downhole formation, the apparatus includes: a fracturing base fluid source; a natural gas source; and a mixer for accepting natural gas from the natural gas source and fracturing base fluid from the fracturing base fluid source and mixing the natural gas and the fracturing base fluid to generate the energized fracturing fluid.

RELATED APPLICATION

This application claims the benefit of U.S. provisional application No.61/433,441 filed on Jan. 17, 2011 and incorporates the entirety of thatapplication by reference.

FIELD

The invention relates to a fracturing system and method for undergroundformations and, in particular, to fracturing using natural gas andpurging using an inert fluid.

BACKGROUND

Hydraulic fracturing is a common technique used to improve productionfrom existing wells, low rate wells, new wells and wells that are nolonger producing. Fracturing fluids and fracture propping materials aremixed in specialized equipment then pumped through the wellbore and intothe subterranean formation containing the hydrocarbon materials to beproduced. Injection of fracturing fluids that carry the proppingmaterials is completed at high pressures sufficient to fracture thesubterranean formation. The fracturing fluid carries the proppingmaterials into the fractures. Upon completion of the fluid and proppantinjection, the pressure is reduced and the proppant holds the fracturesopen. The well is then flowed to remove the fracturing fluid from thefractures and formation. Upon removal of sufficient fracturing fluid,production from the well is initiated or resumed utilizing the improvedflow through the created fracture system. In some cases, such asrecovering natural gas from coal bed methane deposits, proppants are notapplied and the simple act of fracturing the formation suffices toprovide the desired improvement in production. Failure to removesufficient fracturing fluid from the formation can block the flow ofhydrocarbon and significantly reduce the effectiveness of the placedfracture and production from the well. In order to improve fracturefluid recovery, gases, predominantly nitrogen and carbon dioxide areused in hydraulic fracturing operations.

The use of gases in the fracturing process, particularly carbon dioxideand nitrogen, is common within the industry. By using these gases theliquid component of the fracturing fluid can be reduced or eliminated.With less liquid used in the fracture treatment and the high mobilityand expansion of the gas component, the fracturing fluids are mucheasier to remove. Further, replacement of liquids with gases can provideeconomic and environmental benefit by reducing the liquid volume neededto complete the fracturing treatment. Generally fracturing compositionsusing gases can be distinguished as pure gas fracturing (a fluidcomprised of nearly 100% gas including carbon dioxide or nitrogen), amist (a mixture composed of approximately 95% gas (carbon dioxide ornitrogen) carrying a liquid phase), a foam or emulsion (a mixturecomposed of approximately 50% to 95% gas formed within a continuousliquid phase), or an energized fluid (a mixture composed ofapproximately 5% to 50% gas in a liquid phase).

The use of nitrogen or carbon dioxide with oil or water based fracturingfluids has been described in the prior art, and can provide a range ofbenefits. However, in spite of all these benefits, the use of nitrogenor carbon dioxide in fracturing treatments can still have somedetrimental effects on the hydraulic fracturing process, create issuesduring fracture fluid recovery which increase costs and negativelyimpact the environment.

Other gases have been proposed to gain the benefits attained with addinggases to fracturing fluids while avoiding at least some of the inherentdifficulties found with nitrogen and carbon dioxide. Specifically,natural gas has been proposed for use in hydraulic fracturing. Naturalgas may be non-damaging to the reservoir rock, inert to the reservoirfluids, recoverable without contamination of the reservoir gas and isoften readily available.

However, while the use of natural gas for hydraulic fracturingtreatments has been suggested, it is potentially hazardous, and asuitable and safe apparatus and method for hydraulic fracturing usingnatural gas has not been provided.

SUMMARY

According to one aspect of the invention, According to one aspect of theinvention, there is provided a method of operating a formationfracturing system that uses a fracturing fluid comprising natural gas.This method comprises the steps of: (a) providing a formation fracturingsystem including a natural gas supply apparatus comprising a natural gassource, a pump assembly for pressurizing natural gas from the naturalgas source, and fluid supply conduits for transporting the natural gasfrom the natural gas source to the pump assembly and to a wellhead of awell that is in communication with an underground formation to befractured; (b) forming a fracturing fluid by providing natural gas fromthe natural gas source and pressurizing the natural gas to a fracturingpressure of the formation using the pump assembly; (c) injecting thefracturing fluid through the wellhead and into the formation until theformation is fractured; and (d) injecting an inert fluid through atleast part of the formation fracturing system before and/or afterinjecting the fracturing fluid through the wellhead and until the atleast part of the formation fracturing system is purged to anon-flammable state. The inert fluid can be selected from the groupconsisting of nitrogen, helium, neon, argon, kyrpton and carbon dioxideor mixtures thereof.

After injecting the inert fluid through the at least part of theformation fracturing system, the injected inert fluid can be injectedinto the well. This injected inert fluid can be injected into the welluntil the inert fluid contributes to fracturing the formation. Afterdirecting the injected inert fluid into the well, natural gas can beinjected through the system such that inert fluid in the system isdisplaced into the well. Instead of injecting into the well, theinjected inert fluid can be vented after it has been injected throughthe at least part of the formation fracturing system.

The natural gas source can be liquefied natural gas, in which case thenatural gas supply apparatus includes a heater for heating the liquefiednatural gas to an application temperature, and the method furthercomprises injecting a cryogenic inert fluid such as liquefied nitrogenbefore the fracturing fluid is injected into at least part of theformation fracturing system to pre-cool the at least part of theformation fracturing system prior to natural gas injection.

The formation fracturing system can further comprise valves coupled tothe fluid supply conduits, in which case the method further comprisesclosing at least some of the valves to fluidly isolate at least part ofthe formation fracturing system, then injecting the inert fluid into theisolated part of the system and pressure testing the isolated part ofthe system.

The formation fracturing system can further comprise valves coupled tothe fluid supply conduits and a venting conduit fluidly coupled to atleast part of the natural gas supply apparatus, in which case the methodfurther comprises after natural gas has been injected into the wellhead:closing at least some of the valves to isolate at least part of thenatural gas supply apparatus from the rest of the formation fracturingsystem, opening at least some of the valves to vent natural gas from theisolated part of the natural gas supply apparatus and out of the systemvia the venting conduit, then injecting the inert fluid into theisolated part of the natural gas supply apparatus for purging thereof.

The system can further comprise: a base fluid supply apparatus and amixer fluid coupled to the base fluid supply apparatus and natural gassupply apparatus and to the wellhead. In such case, the method furthercomprises forming a fracturing fluid mixture comprising a base fluidfrom the base fluid supply apparatus and the natural gas in the mixer,then injecting the fracturing fluid mixture into the wellhead until theformation is fractured. Before injecting natural gas into the wellhead,the inert fluid is injected through the natural gas supply apparatus andmixer until they are purged to a non-flammable state. The ventingconduit can be further coupled to at least part of the base fluid supplyapparatus and the mixer, in which case the method further comprisesafter natural gas has been injected into the wellhead: isolating atleast part of the base fluid supply apparatus or mixer or both, theninjecting the inert fluid therethrough and out of the system via theventing conduit.

According to another aspect of the invention, there is provided a systemfor fracturing a downhole formation, comprising: a natural gas supplyapparatus comprising a natural gas source, a pump assembly forpressurizing natural gas from the natural gas source to a fracturingpressure of a downhole formation, and natural gas fluid supply conduitsfluidly coupling the natural gas source to the pump assembly and to awellhead of a well that is in communication with the downhole formation;an inert fluid supply apparatus comprising an inert fluid source andinert fluid supply conduits fluidly coupling the inert fluid source toat least part of the natural gas supply apparatus; a venting conduitfluidly coupled to at least part of the natural gas supply apparatussuch that natural gas and inert fluid can be vented from the system; andvalves coupled to at least the natural gas and inert fluid supplyconduits that can be selectively opened and closed to inject the naturalgas through the wellhead until a formation is fractured, and to injectthe inert fluid through at least part of the natural gas supplyapparatus for purging thereof either before or after the natural gas isinjected into the wellhead.

The inert fluid supply apparatus can further comprise a pump for movingthe inert fluid through and out of the at least part of the natural gassupply apparatus. The inert fluid supply apparatus can further comprisea nitrogen source or a carbon dioxide source.

The system can further comprise a base fluid supply apparatus and amixer fluidly coupled to the base fluid supply apparatus, natural gassupply apparatus and to the wellhead. The base fluid supply apparatuscan comprise a base fluid source, a base fluid pump and base fluidsupply conduits for fluidly coupling the base fluid source to the basefluid pump and to the mixer. The base fluid supply apparatus can furthercomprises a proppant supply and a blender fluidly coupled to theproppant supply and the base fluid source and the base fluid pump, or achemical source and a blender fluidly coupled to the chemical source andthe base fluid source and the base fluid pump, or a chemical source, aproppant supply, and a blender fluidly coupled to the proppant supply,chemical source, base fluid source, and the base fluid pump. Thechemical source in any of these cases can be a viscosifier source.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments of the invention will now be described with reference to theaccompanying drawings in which:

FIG. 1 is a generically depicted schematic of a fracturing system forinjecting a fracturing fluid mixture of natural gas and a base fluidinto an underground formation according to at least some of theembodiments.

FIG. 2 is a schematic illustrating the main components of a fracturingsystem as shown in FIG. 1, which includes compressed natural gas storageand supply equipment according to a first embodiment.

FIG. 3 is a schematic illustrating the main components of a fracturingsystem as shown in FIG. 1 which includes liquefied natural gas (LNG)storage and supply equipment according to a second embodiment.

FIG. 4 is a schematic illustrating the main components of an LNGfracturing pump assembly used in the second embodiment.

FIG. 5 is a schematic illustrating a natural gas and fracturing slurrystream mixer for at least some of the embodiments.

FIG. 6 is a schematic illustrating a fracturing system for injecting afracturing fluid comprising a pure stream of natural gas into anunderground formation according to a third embodiment.

FIG. 7 is a schematic illustrating a fracturing system for injecting afracturing fluid mixture comprising natural gas and proppant into anunderground formation according to a fourth embodiment.

FIG. 8 is a schematic illustrating a fracturing system for injecting afracturing fluid mixture comprising natural gas and a base fluid withoutproppant into an underground formation, according to a fifth embodiment.

FIG. 9 is a schematic showing a fracturing system for injecting afracturing fluid mixture into an underground formation wherein thesystem includes venting, purging and isolation equipment, according to asixth embodiment.

FIG. 10 is a schematic illustrating LNG storage and vapor managementequipment used in the second embodiment.

FIG. 11 is a schematic illustrating a controller for controlling thefracturing system of some of the embodiments.

FIG. 12 is a schematic showing an exemplary surface equipment layout ofat least some embodiments of the fracturing system.

FIG. 13 is a schematic showing a section generally along line I-I ofFIG. 10.

FIG. 14 is a schematic showing catalytic vaporizer of another embodimentof a liquefied natural gas fracturing pump assembly.

FIG. 15 is a process flow diagram illustrating a method for fracturingan underground formation with a fracturing fluid mixture using afracturing system according to at least some of the embodiments.

FIG. 16 is a schematic showing a fracturing system for injecting afracturing fluid mixture into an underground formation wherein thesystem includes venting and purging and isolation equipment, accordingto another embodiment.

DETAILED DESCRIPTION Introduction

The description that follows, and the embodiments described therein, isprovided by way of illustration of an example, or examples, ofparticular embodiments of the principles of various aspects of thepresent invention. These examples are provided for the purposes ofexplanation, and not of limitation, of those principles and of theinvention in its various aspects. In the description, similar parts aremarked throughout the specification and the drawings with the samerespective reference numerals. The drawings are not necessarily to scaleand in some instances proportions may have been exaggerated in ordermore clearly to depict certain features.

The embodiments described herein provide apparatuses, systems andmethods for fracturing a formation in a subterranean reservoir with afracturing fluid mixture comprising natural gas and a base fluid, orwith a natural gas-only fracturing fluid. In a first embodiment, afracturing system is provided which injects a fracturing fluid mixturecomprising natural gas and a base fluid, wherein the natural gas isstored as compressed natural gas (CNG) and wherein the base fluid caninclude a fracturing liquid, a proppant and a viscosifier. In a secondembodiment, a fracturing system is provided which injects a fracturingfluid mixture comprising natural gas and a base fluid, wherein thenatural gas is stored as LNG and wherein the base fluid can include afracturing liquid, a proppant and a viscosifier. In a third embodiment,a fracturing system is provided which injects a fracturing fluidconsisting only of a natural gas stream. In a fourth embodiment, afracturing system is provided which injects a fracturing fluid mixtureconsisting only of a natural gas stream and a proppant. In a fifthembodiment, a fracturing system is provided which injects a fracturingfluid mixture comprising natural gas and a base fluid, wherein the basefluid is free of proppant. In a sixth embodiment, a fracturing system isprovided which injects a fracturing fluid mixture comprising natural gasand a base fluid and which includes natural gas venting and purgingequipment. Each of these embodiments will be described in greater detailbelow.

As used in this disclosure, natural gas means methane (CH₄) alone orblends of methane with other gases such as other gaseous hydrocarbons.Natural gas is often a variable mixture of about 85% to 99% methane(CH₄) and 5% to 15% ethane (C₂H₆), with further decreasing components ofpropane (C₃H₈), butane (C₄H₁₀), pentane (C₅H₁₂) with traces of longerchain hydrocarbons. Natural gas, as used herein, may also contain inertgases such as carbon dioxide and nitrogen in varying degrees thoughvolumes above approximately 30% would degrade the benefits received fromthis work. CNG refers to compressed natural gas. LNG refers to liquefiednatural gas.

A natural gas stream for hydraulic fracturing may be provided as a gasand at pressure and rate sufficient to support the hydraulic fracturingof the subterranean reservoir. The natural gas stream may be blendedwith a base fluid to form a fracturing fluid mixture, or injected as apure stream (i.e. without a base fluid) or blended only with a proppant.The base fluid can comprise a fracturing liquid such as a conventionalhydrocarbon well servicing fluid, a fracturing liquid containing one ormore proppants and/or one more viscosifiers or rheology modifiers suchas friction reducers. Hydraulic energy to create the fracture in thesubterranean reservoir is obtained from pressurization of the gaseousnatural gas and the base fluid mixture at surface at combined ratessufficient to impart the needed energy at the subterranean reservoir.Following the fracture treatment, the natural gas and accompanyingfracturing liquid can be recovered and the applied natural gas energizerdirected to existing facilities for recovery and sale.

A fracturing system is provided which includes equipment for storing thecomponents of the fracturing fluid mixture, equipment for injecting thenatural gas-containing fracturing fluid mixture into a subterraneanformation, such as an oil well or a gas well, and equipment forrecovering and separating fluids from the well. In some embodiments, thenatural gas source is compressed gas (CNG) held in pressurized vesselswith a fracturing pump further compressing the natural gas to a suitablefracturing pressure. In other embodiments, the compressed gas is held inpressurized vessels above the fracturing pressure and simply releasedinto the fracturing stream. In some embodiments, the gas source is avessel containing liquefied natural gas (LNG) with the fracturing pumppressuring the LNG to fracturing pressure and heating the pressurizedLNG stream.

Efficient storage of gaseous phase natural gas is achieved at thehighest possible pressure which is typically less than 30 MPa (4,400psi). Pressurization of the natural gas to the extremes typically neededfor hydraulic fracturing can be accomplished with the feed in a gaseousphase. Gas phase compressors have been applied to pressures approaching100 MPa (15,000 psi) which are thus suitable for compressing the naturalgas to a suitable fracturing pressure.

Fracturing fluid streams containing natural gas improve fracturing fluidremoval from the well and hence post-fracture production performance.Using natural gas avoids fluid incompatibilities often found with theuse of carbon dioxide or nitrogen as the energizing fluid. Uponcompletion of the fracturing treatment, the natural gas component isrecovered with the fracturing fluid and the reservoir oil and/or gas.The injected natural gas is recovered within the existing oil and/or gasprocessing system with little or no disturbance to normal operations.This might eliminate venting or flaring typical to energized fracturetreatments as needed to achieve suitable gas composition for sales gas.Further, using natural gas in the fracturing fluid stream may enableapplication of a locally available gas to gain the benefit of a gasifiedfracturing fluid stream without the extensive logistics often associatedwith nitrogen or carbon dioxide.

FIG. 1 is a generic depiction of the main components of the fracturingsystem according to those embodiments which utilize a fracturing fluidmixture comprising natural gas and a base fluid that may contain aproppant and/or a chemical additive. A fracturing liquid is stored in afracturing liquid tank (13), proppant is stored in a proppant container(12), and chemical additives such as a viscosifier is stored in achemical additive container (22). Natural gas is stored in a natural gascontainer (15) and a natural gas stream is pressurized and supplied by ahigh pressure natural gas pump (17) and enters a fracturing fluid mixer(18) via a conduit (24). The natural gas stored in container (15) can becompressed natural gas or liquefied natural gas. The high pressurenatural gas pump (17) is a compressor if compressed natural gas is thesource or a specialized liquefied natural gas fracturing pump ifliquefied natural gas is the source. The output from the high pressurenatural gas pump (17), regardless of the state of the source gas, is ina gaseous state.

Within the mixer (18), the natural gas stream from conduit (24) iscombined with a liquid-phase base fluid stream from conduit (42); thisbase fluid can comprise the fracturing liquid optionally combined withproppant and the chemical additive. The combined fracturing mixture thenenters a well (19) via a conduit (25) where it travels down the wellboreto the reservoir creating the hydraulic fracture using the rate andpressure of the fracturing fluid mixture. Upon applying the desiredfracturing materials within the well (19), injection is stopped andplacement of the fracturing treatment is complete. Following thefracture treatment and at a time deemed suitable for the well beingfractured, the well (19) is opened for flow with the stream directed toa conduit (20 a) and then through a separator vessel (60) wherein gasesare separated from liquids. Initial flow from the well will be mostlycomprised of the injected fracturing materials and the separator vessel(60) is used to separate the injected natural gas from the recoveredstream through the conduit (20 a). The liquids and solids recovered fromseparator vessel (60) are directed to tanks or holding pits (not shown).The natural gas from the recovered stream exits the separator (60) andis initially directed to a flare (20) until flow is suitably stabilized,then directed to a pipeline (21) for processing and sale.

In further embodiments, there are provided methods of fracturing a wellusing a natural gas or a mixture of natural gas and a base fluid. Anumber of specific methods pertain to safely and reliably applyingnatural gas in the form of liquefied natural gas. Methods using LNG foron-site storage may permit considerable volumes to be stored efficientlyand at pressures as low as atmospheric. As a cryogenic liquid one unitvolume of LNG contains approximately six hundred volumes of gas atatmospheric conditions. Thus, fewer storage vessels and a much lowerstorage and feed pressure with reduced flow volumes is required comparedto compressed natural gas. Similarly, pressuring natural gas to theextreme pressures encountered in hydraulic fracturing in liquid form asLNG is exceptionally efficient. Again, as a liquid the volumetric ratesare much reduced and relatively incompressible as compared to compressednatural gas, compression heating is eliminated and equipment size andnumbers drastically reduced. This significantly reduces the complexityof the operation removing many of the costs and hazards which would bepresent with known techniques. Further, with fewer pieces of equipmentoperating at lower pressures with fewer connections between equipment,the needed simplicity for frequent movement of the equipment betweenwells is supported with LNG use. An inert cryogenic gas at a temperaturenear or below that of the liquefied natural gas is used to quickly,efficiently and safely pre-cool the natural gas pumper and heater tooperating temperature prior to introducing the cryogenic LNG. Thiseliminates or minimizes use of LNG for cool down thereby avoiding theunnecessary flaring and potential safety issues around cooling thesystem with the flammable liquefied gas. On-site pressure integrity ofthe cryogenic liquefied natural gas pumping and heating system ismaximized by combining the pumping and heating system on a single unitthat is permanently combined. LNG storage tanks are designed to operateunder elevated pressures to eliminate or minimize vent gases duringstorage. The elevated pressure capacity also allows for boostpressurization during LNG withdrawal from the storage tanks atfracturing rates thereby assisting feed to the LNG pumps. As a sidestream, vapor from the LNG fracturing pump is directed, as needed to theLNG storage tanks to maintain vessel pressure and create the boost.Energy for heating of the LNG can be acquired in a number of ways, wherea preferred embodiment employs heat that is generated without a flame.Such heat for a portable unit can be acquired from the environment,waste or generated heat from internal combustion engine, a catalyticburner or an electric heating element. Alternatively heat can begenerated using a flame based heat source local to the heater or remoteto the process as dictated by safety requirements.

The embodiments described herein therefore provide for a fracturingsystem and a method of using the fracturing system and a fracturingfluid mixture to fracture an underground formation. Natural gas used inthe fracturing fluid mixture may be readily available at reasonablecost, is environmentally friendly and is commercially recoverable. Itsuse as a gas phase is beneficial to improve post-fracture oil and gasproduction while it is also suitable as a substitute for fracturingfluid liquid volumes thereby reducing environmental impact andfracturing costs. The capability to recover the gas through existingproduction facilities can substantially reduce flaring, save time toplacing the well on production and permit immediate gas revenues fromthe well. Further, the technique is applicable to conventional andunconventional oil and gas wells and suitable for fracturing withhydrocarbon based liquids, water based liquids and acids.

First Embodiment: Fracturing System Using Fracturing Fluid MixtureComprising A Base fluid and Natural Gas From a Compressed Natural GasSource

According to a first embodiment and referring to FIG. 2, a system isshown for fracturing a subterranean reservoir penetrated by a well usinga fracturing fluid mixture. The fracturing fluid mixture is formed byblending a natural gas stream with a base fluid, wherein the natural gasis from a compressed natural gas source. The base fluid comprises afracturing liquid and can further comprise viscosifying chemicals and aproppant. More particularly, the fracturing liquid may be any of oil,water, methanol, acid or combinations as desired. The proppant may benatural frac sand or a manufactured particle. The chemical additiveswill be products as typically applied to create viscosity within theliquid, reduce friction or create beneficial properties as desired.

The main components of the system include a fracturing liquid supplytank, equipment for conveying and prepping the base fluid forcombination with a natural gas stream, a natural gas container,equipment for conveying the natural gas stream for combination with thebase fluid, a mixer for combining the base fluid and the natural gasstream to form the fracturing fluid mixture and equipment for conveyingthe fracturing fluid mixture to the wellhead. The specific components ofthe fracturing system will now be described. A fracturing liquid tank(13) suitable for water or hydrocarbon based liquids is connected via aconduit (26) to a fracturing blender (14) with viscosifying chemicalsadded via a conduit from chemical additive container (22). Thefracturing liquid tanks (13) can be any of those common within theindustry for hydraulic fracturing and may apply more than one tank orother suitable arrangement to store sufficient liquid volume. Theconduit (26) like all other conduits shown on the FIG. 2, is a pipe orhose rated to the described application and conditions. The blender (14)receives the viscosified fracturing liquid and blends proppant from aproppant supply container (12) with the fracturing liquid to form thebase fluid which is now in a slurry form. The blender (14) is a multipletask unit that draws liquids from the fracturing fluids tank with acentrifugal pump (not shown), accepts chemicals from the chemicaladditive container (22) and mixes them with the fracturing fluid, oftenwithin the centrifugal pump.

The fracturing liquid is combined with proppant from proppant supplycontainer (12) in a mixing tub or other mixing device on the blender(14) and then drawn into another centrifugal pump mounted on the blender(14). An example of a typical blending unit is the MT-1060 trailermounted fracturing blender supplied to the industry by National OilwellVarco. An example of a proppant supply vessel (12) is the 110 m3 (4,000cu. ft.) vessels referred to as ‘sand kings’ capable of delivering 9tonnes (20,000 lbs) proppant per min.

The created slurry base fluid is then pumped via a conduit from theblender (14) to a high pressure slurry pump (16). The high pressureslurry pump (16) pressurizes the base fluid stream to a suitablefracturing pressure and is connected via a conduit (25) to a fracturingfluid mixer (18). An example of a high pressure fracturing pump is adiesel powered Quintuplex positive displacement pump mounted on atrailer generating up to 1,500 kW or 2,000 HHP. More than one pump maybe used as the pump (16). Some of the foregoing components may becombined such as the blender (14) and high pressure slurry pump (16).

In this embodiment, the natural gas source is one or more vessels (15)containing compressed natural gas (CNG). An example of a vessel appliedfor compressed natural gas transport and storage is the trailer mountedLincoln Composites' TITAN Tank holding up to 2,500 scm (89,000 scf) ofCNG at pressures to 25 MPa (3,600 psi). The CNG storage vessel (15) isconnected to a high pressure natural gas compressor pump, herein shownas pumps (127 a, 127 b, 127 c), via conduit (123) with control valve(V4) and is used to compress the gas to the fracturing pressure.Compression may be accomplished by any pump capable of increasing thepressure within a gas stream; for example reciprocating compressors maybe applied to achieve high pressure such as that required for hydraulicfracturing. Typically compressors achieve a fixed compression factor,such that multiple stages of compression may be required to attainfracturing pressure. Similarly, in order to achieve the desired rate, amultiple of compressor stages may be applied in parallel. The compressorpump (127 a, 127 b, 127 c) is shown with three compression stages thoughmore or fewer compressor stages may be needed to achieve the desiredoutlet pressure. Flow of the compressed natural gas from the storagevessel (15) to the high pressure natural gas compressor pumps (127 a,127 b, 127 c) is controlled with a valve (V4). The compressor pump (127a, 127 b, 127 c) is connected to the fracturing fluid mixer (18) viaconduit (24) with gas control valve (V61). Flow of the pressured naturalgas from the high pressure natural gas compressor pumps (127 a, 127 b,127 c) to the fracturing fluid mixer (18) is controlled with valve(V61). Should the pressure of the compressed gas within the vessel besufficiently above the fracturing pressure, the gas can be controlled byvalves (V4) and (V61) directly to the natural gas slurry stream mixervia conduit (128) and bypassing the high pressure natural gas pumpcompressors (127 a, 127 b, 127 c) using valve (V4).

Second Embodiment: Fracturing System Using Fracturing Fluid MixtureComprising A Base fluid and Natural Gas from a Liquefied Natural GasSource

Referring to FIGS. 3, 10 to 14 and according to a second embodiment, aformation fracturing system is provided which uses a fracturing fluidmixture comprising a base fluid and natural gas from a liquefied naturalgas source. In particular, the fracturing system includes an LNG storageand vapor management sub-system for storing LNG and pressurizing andheating the LNG to the application temperature then supplying thenatural gas to be mixed with the base fluid. In this embodiment, the LNGis heated to a temperature wherein the natural gas is in a vapour phase;however, it is conceivable in other embodiments that the natural gas canbe heated to a temperature wherein the natural gas remains in a liquidphase. FIG. 3 shows the fracturing system of FIG. 1 with such a LNGstorage and vapor management sub-system.

In this embodiment, the natural gas source (215) is one or more vesselscontaining liquefied natural gas (LNG). An example of a vessel appliedfor natural gas storage is the skid mounted EKIP Research and ProductionCompany LNG Transporter with a capacity of 35.36 m³ (9,336 gal) holdingup to 21,000 scm (750,000 scf) of liquid natural gas at pressures to 0.6MPa (90 psi). LNG is typically stored at atmospheric pressure at atemperature of approximately −162° C. (−260° F.). The LNG storage vessel(215) is connected to high pressure natural gas fracturing pump assembly(229) via LNG supply conduit (223) with supply valve (V42). The highpressure natural gas fracturing pump assembly (229) is arranged topressure the LNG to the fracturing pressure with pump component (230)and then heat the pressured LNG to compressed gas with heater component(231) of the pump assembly (229). The supply conduit (223) is a fit forpurpose LNG conduit such as a 4014SS Cryogenic 50 Series: Cryogenic Hosemanufactured by JGB Enterprises Inc.

Replacement for liquid volumes removed from LNG storage vessel (215), isaccomplished by directing a stream of the created pressurized gas fromheater component (231) through return conduit (232) with control of thestream by return valve (V11). The replacement vapor is controlled tomaintain suitable pressure within the LNG vessel (215). Transfer of LNGfrom the storage vessel (215) to the natural gas fracturing pumpassembly (229) is supported by the returning vapor stream in returnconduit (232) providing sufficient pressure in the natural gas source(215) to supply the stream of LNG to the inlet of the high pressurenatural gas fracturing pump assembly (229). In one configuration thenatural gas fracturing pump assembly (229) combines pressurization andheating of the LNG within a single unit, for example, in one housing, ona self contained skid, through one active device, etc. However, thesesteps can be accomplished on separate units. All components contacted bythe LNG must be suitable for cryogenic service. Flow of the pressurednatural gas from the natural gas fracturing pump assembly (229) to thenatural gas slurry stream mixer (18) is controlled with valve (V6) andthrough natural gas supply conduit 24.

Referring to FIGS. 10 and 13, the LNG storage and vapor managementsub-system is used to store and manage the LNG used by the fracturingsystem. Management and control of the LNG storage is needed to maintaina non-hazardous work area while the LNG is stored awaiting use. Understorage at −162° C. (−260° F.) and atmospheric pressure LNG will slowlyheat and vaporization of the liquid occurs to maintain its equilibriumstate. The generated gases are then by necessity vented from the tank inorder to avoid over pressuring.

The LNG storage and vapor management sub-system comprises the LNG source(215) which can be a single or multiple LNG tanks (715). Control ofpressure in each of these tanks (715) is accomplished by a pressurerelief valve V18 with a relief setting based on the operating design ofthe tank. The relief valve (V18) is communicative with each tank (715)via a collected vapour conduit (62) and intertank vapour line conduit(61) which in turn is coupled to a vapour line 63 in each tank. In oneconfiguration, relief valve (V18) is connected to a flare line conduit(720 a) and then to flare 20 (the connection of conduit 720 a to flare20 not shown in Figures) where released vapors are safely burned.

Alternatively, the collected vapor can be again liquefied and pumpedback into the LNG storage tanks (715) creating a safe, efficient andenvironmentally friendly closed vapor system: collected vapor conduit(62) is diverted to conduit (53) through valve (V17) to a nitrogenexpander liquefaction unit (55). A liquid nitrogen source (57) suppliescryogenic nitrogen through nitrogen supply conduit (52) to the nitrogenexpander liquefaction unit (55) where vaporization of the nitrogencauses sufficient cooling to re-liquefy the natural gas vapors to LNG.The produced LNG is then pumped through a return conduit (54) into theliquid load line of the LNG source vessels (715); the return conduit(54) also serves to fill the tanks (715) as necessary. The LNG tanks(715) are fluidly interconnected via their liquid load lines (54) viaconduit (56) to ensure equal distribution of the LNG between all tanks.Further, the LNG tanks (715) are fluidly interconnected via their vaporlines (63) by conduit (61).

Return conduit 232 from the natural gas fracturing pump assembly 229 isshown as conduit (732) in FIGS. 10 and 13, and serve to returnpressurized gaseous natural gas back to the tanks (715) to pressurizethe tanks (715) as necessary. Flow from return conduit (732) iscontrolled using valve (V22) which in turn is coupled to conduit (61).

Liquid natural gas is supplied from the tanks to the natural gasfracturing pump assembly 229 via conduit 223; flow is controlled fromeach tank by control valve (V42).

In an alternative embodiment, the LNG tanks (715) can be designed toallow pressures as high as 2 MPa (300 psi) before pressure relief isrequired. When loading these tanks (715) with LNG at normal conditionsof −162° C. (−260° F.) the elevated relief pressure will delay ventinguntil temperatures reach levels approaching −110° C. (−166° F.) arereached. With the minimal heat gain imparted by the insulatingproperties of LNG tanks, venting can be virtually eliminated with normalusage cycles. Additionally, providing elevated relief pressure in theLNG source (55) ensures small errors in pressure maintenance duringpumping, vapor from the LNG fracturing pump heater (31), and the desireto boost the internal pressure of the tanks to ensure reliable feed tothe natural gas fracturing pump assembly (229) and do not result inopening of pressure relief valves during the fracturing process.

FIG. 4 is a schematic illustrating the main components of the naturalgas fracturing pump assembly (229). LNG is fed to the pump component(230) from supply conduit (223). The pump component comprises acryogenic centrifugal pump (233), a high pressure LNG pump (235) and aconduit (234) interconnecting the cryogenic centrifugal pump (233) andthe LNG pump (235). Adequate feed pressure to the high pressure LNG pump(235) is needed to ensure vapor-lock or cavitation does not occur withinthe pumping cycle. A single or multiple cryogenic centrifugal pumps(233) may be applied as needed to meet the feed pressure and raterequirement to support the high pressure LNG pump (235). An example of acryogenic centrifugal pump (233) to provide feed pressure and rate isthat of ACD Industries, Boost Pump 2×3×6 providing rates to 1.5 m3/min(2400 gpm) LNG and a pressure head of 95 kPa (15 psi). The high pressureLNG pump (235) is rated to pressurize LNG to at least 35 MPa and up toas high as 100 MPa (15,000 psi) in order to provide sufficient pressureto fracture the formation. A positive displacement pump such as a pistonpump can be used to achieve these pressures though other pump stylesgenerating sufficient rate and pressure can also be applied. An exampleof such a pump is the ACD Industries' 5-SLS series cryogenic pumps ratedto pressures of 124 MPa (18,000 psi) with LNG rates to 0.5 m3/min (132gpm). Single or multiple high pressure LNG pumps (235) may be applied tomeet the fracturing feed rate requirement. Power needed to drive thepumps (233) and (235) can be obtained from an internal combustion enginethrough direct drive, generated electricity, or hydraulics as desired.

Pressured LNG exiting from the high pressure LNG pumps (235) is directedto a heater assembly (231) using conduit (236) to heat the natural gasto the application temperature, which in this specific embodimentchanges the phase of the natural gas from liquid to gas. Generally, theminimum temperature to heat LNG is approximately −77° C. (−107° F.) andthis temperature is where many carbon steels transform from austenite tomartensite crystals with a corresponding change in metallurgy. In oneembodiment, a natural gas outlet temperature to conduits (24) and (232)is in the range of 0° C. (32° F.) to 20° C. (68° F.) to avoid contactedliquid freezing issues and to maintain elasticity of seals. Within theheater assembly (231) is a heat exchanging system as needed to transferheat to the LNG, and in this embodiment comprises a first heatexchanger(237), a second heat exchanger (239) downstream of the firstheat exchanger, and a natural gas supply conduit (238) which extendsfrom the supply conduit 236 and through the two heat exchangers 237,239, and which couples to supply conduit 24 as well as return valve(V11). Return valve (V11) in turn is coupled to return conduit (232).

In this embodiment, the LNG is first heated by heat source (240) whichis proposed as heat derived from air, typically driven across the heatexchanger coils within the first heat exchanger (237) by a blower (notshown). LNG at a temperature approaching −162° C. (−260° F.) can derivesignificant energy from air resulting in a lightened heating load. Thedischarge from the first heat exchanger (237) is then directed to theheat exchanger coils within the second heat exchanger (239) through thesupply conduit (238). Within the second heat exchanger (239), the LNG isheated to the target outlet temperature by another heat source (241).The energy available from this other heat source (241) must besignificant in order to support rapid heating of the LNG. The heatsource (241) can be generated without flame and may be waste orgenerated heat from an internal combustion engine, a catalytic burner oran electric element. Alternatively heat can be generated using a flamebased heat source local to the heater or remote to the process asdictated by safety requirements. Outlet of the pressurized gaseousnatural gas is via supply conduit (24) with gas control valve (V6) tothe natural gas slurry stream mixer (18).

Once the natural gas has been sufficiently heated (which in thisspecific embodiment means vaporized into a gaseous state), it flowsthrough supply conduit (24) and is mixed with the base fluid in thefracturing fluid mixer (18). The fluid pressures handled in the mixer(18) may be significant, fluid abrasion may be a significant factor andleaks are to be avoided. With respect to throughput, effective componentmixing is important. While various types of mixers may be useful, onesuitable mixer (318) for a compressed natural gas and fracturing slurrystream is shown in FIG. 5. The natural gas slurry stream mixer (318)works to combine and mix a base fluid stream from conduit (342) with thegaseous natural gas stream from supply conduit (324) within a mixer body(343). Achieving a good mix of the fracturing liquid stream, proppantand the gaseous natural gas stream, can contribute to creating thedesired structure and behavior of the fracturing fluid mixture for anenergized fluid, foam or a mist. For example, proper foam developmentrequires the gas phase to be completely dispersed within the liquidphase with bubble sizes as small as possible. Sufficient dispersion canbe achieved in a number of ways, one of which is represented by a chokedevice (344) in the natural gas stream conduit which by virtue ofdecreasing the flow area increases the velocity of the natural gasstream. Contact of the natural gas stream with the fracturing liquidstream at a high velocity promotes good mixing. Other mechanisms can beemployed to promote mixing including internal diverters, turbulizers andvarious static or dynamic mixing devices. To safely managing afracturing stream containing natural gas, it should be recognized thatslurries containing gases can have very high velocities that can quicklyerode pressure containing components.

Combining a base fluid slurry stream with a natural gas stream and thenfurther transporting the resultant mixture through conduits andwellbores is done with the recognition that particle (proppant) impacton flow path changes can quickly result in component failure andhazardous release of the flammable gas. As such, a mixer (18) isprovided that allows the base fluid containing liquid/proppant to passin a substantially straight path through the mixer. For example, thebase fluid conduit (342) may define a substantially linear innerdiameter and conduit (324) may join conduit (342) at an angle. In oneembodiment, for example, the mixer (18) includes a main flow lineincluding an inlet end and an outlet end, an elbow conduit connected toand in fluid communication with the main flow line between the inlet endand the outlet end, the elbow conduit extending at an acute angle fromthe inlet end and a substantially linear flow path through the main flowline, the inlet end connected to receive flow from the fracturing basefluid source and the elbow conduit connected to receive flow from thenatural gas source. Upon leaving the mixing body (343) the fracturingfluid mixture is then directed via a conduit (325) to the wellhead anddown the wellbore to create the hydraulic fracture in the subterraneanreservoir.

Referring to FIG. 11, the fracturing system can be controlled remotelyby a controller (58); the configuration and operation of the controller(58) is described further in the sixth embodiment below. In this secondembodiment, control functions from controller (58) are completed throughwireless communication to the controlled components as presented in FIG.11. Application may involve control through wires or by a combination ofwire based and wireless communications. In this embodiment thecontroller (58) is presumed a computerized control station mountedwithin a cabin on a truck chassis. The system can be manipulated topermit pumping of only natural gas or liquid, only liquid-slurry or anydesired combination of natural gas, liquid and liquid-slurry. In someapplications only natural gas will be pumped for a portion of thetreatment, such as with a pre-pad or treatment flush. Alternatively,only liquid or liquid-slurry will be pumped, again with the liquid as apre-pad, pad or flush and only liquid-slurry as a stage within thetreatment. Following the treatment, the equipment is shut down, thewellhead valve (V7) closed and preparations are made for rigging off thesite or for completion of another fracturing treatment. The LNG storagevessels are secured with closing of valves (V4) and opening of valve(V18). Valve (V5) is closed and valve (V8) is opened to allow highpressure natural gas to vent from natural gas treating line (24),treating line (25) and LNG fracturing pumpers (229). When the highpressure system has been vented to a nominal pressure, the LNGfracturing pumpers (229) are operated at low capacity to remove LNG fromthe low pressure conduit (23) into the pumps and through the heaterswith discharge through treating line conduits (24), (25) through valve(V8) and to the flare system, separator (60) and flare (20).Alternatively, valve (V13) can be opened to vent the high pressuresystem. Valve (V8) or valve (V13) may be in the form of a choke in orderto control pressure and rate into the separator and flare system.Gaseous nitrogen is simultaneously introduced to conduit (23) from inertgas source (45) via conduit (46) to assist displacement of the lowpressure LNG through the LNG fracturing pumpers (229) to the flare (20).Upon displacing all natural gas liquids from the low pressure conduit(23), valve (V14) is opened to vent and completely purge the lowpressure system. Correspondingly, valve (V15) is opened and gaseousnitrogen is directed through natural gas treating line (24) to completepurging of the high pressure system. In all cases, flow is directed tothe flare until the natural gas content is well below the flammablelimit. Natural gas content can be assessed with a hydrocarbon contentgas stream monitor. With the natural gas purge of the system complete,the treating lines can be rigged from the well (19) and flow back andevaluation of the fracturing treatment initiated. Flow back is initiatedby opening wellhead valve (V7) with flare line valve (V8) and (V20)opened and pipeline valve (V9) closed. Flow is directed through flareline (20 a) and separator (60) to the flare (20). Separator (60)captures liquids and solids while releasing gas to the flare. Liquidsare accumulated within the separator (60) and drained into storagevessels, not shown. Produced solids may include formation fines andfracturing proppant and are accumulated within the separator vessel (60)and removed as needed for continued operation of the separator. Uponachieving stable flow and sufficient gas phase pressure to allow flowinto the pipeline, the flare is shut in with valve (V21) and flowdirected to the sales pipeline (21) by opening valve (V9). Flow from thewell (19) continues to be directed through the separator (60) with gasto the pipeline (21) until the fracturing treatment is sufficientlycleaned up and the well evaluated. The well can then be placed onproduction.

Referring to FIG. 14 an alternative apparatus for heating of LNGcomprises a catalytic heater for use within the LNG fracturing pumper.The catalytic elements (66) radiate heat generated by oxidation of afuel gas such as natural gas, propane or other suitable fuel with oxygenin the presence of a catalyst such as platinum. The fuel gas with air isinjected, injection not shown, into the catalytic elements with theresultant heat being radiated to the LNG exchanger tube (67). Thisprovides the energy needed to sufficiently heat the LNG to applicationtemperature. In the depiction of FIG. 14, eight catalytic elements (66)are arranged concentrically in a bundle around a LNG exchanger tube (67)forming a catalytic bundle (68) for a single pass through the catalyticheating system. Each LNG exchange tube (69) flows natural gastherethrough and includes fins on an outer surface thereof to increasethe surface area which heats, and serves to conduct the heat to theconduit of, the exchanger tube (69) wall for heating of the LNG. Fourbundles are depicted with four groups of eight catalytic elements ineach bundle heating a LNG exchanger tube (67). LNG inlet flow from theambient pre-heater through conduit (238) is split to two of thecatalytic bundles in this configuration. The schematic further showsthat the LNG exiting from one catalytic bundle (68) is directed toanother catalytic bundle (68) for additional heating. The configurationand arrangement of the catalytic bundles, and the flow path through thecatalytic bundles, is can be varied as desired to achieve the heatingtarget. Catalytic elements typically generate 35 Btu/hr for each squareinch (15 kW/m2) of surface area such that the eight element bundle withelements of 26″ (0.67 m) width and 120″ (3 m) length will produce over870,000 Btu/hr (255 kW) of energy. For the illustrated four bundlesystem, a generation rate approaching 3,500,000 Btu/hr (1025 kW) ofenergy is available. This energy level is more than sufficient to meetthe heating capacity needed for a LNG fracturing pumper at 5,600 scf/min(160 sm3/min), yet is a safe and compact arrangement. As a catalyticprocess, the operational surface temperature of a catalytic heatingelement is in the range of 700° F. (370° C.) to 1,000° F. (540° C.),well below the auto-ignition temperature of natural gas in air at 1076°F. (580° C.). The catalytic heater thereby provides an intrinsicallysafe, flameless heat source for heating potentially flammable LNG.

Third Embodiment: Fracturing System for Injecting a Fracturing FluidComprising a Pure Stream of Natural Gas

According to a third embodiment, and referring to FIG. 6 a fracturingapparatus is provided which uses a fracturing fluid comprising a purestream of natural gas, wherein “pure” means without a base fluid orproppant component. Fracturing with a pure stream of natural gas can bebeneficial in situations where any liquid is undesirable and proppant isnot needed to maintain the created fracture system during production.This is often the case for fracturing coal bed methane wells or lowpressure shale formations where liquid removal can be difficult. In thisembodiment, a natural gas source (415) is one or more vessels containingeither of compressed natural gas or liquefied natural gas. The naturalgas source (415) is connected to a high pressure natural gas pump (417)via conduit (423) with valve (V44) for control of the natural gas feed.The high pressure natural gas pump is a compressor applying gascompression in the case of a CNG source and is a cryogenic pump andheater in the case of a LNG source. The prepared natural gas streamleaves the high pressure natural gas pump (417) via conduit (24),through valve (V74) conduit (425) and into the wellhead (19). The puregas stream then travels down the wellbore to create the hydraulicfracture in the subterranean reservoir.

Fourth Embodiment: Fracturing System for Injecting a Fracturing FluidMixture Comprising Natural Gas and Proppant But No Fracturing Liquid

According to a fourth embodiment and referring to FIG. 7 a fracturingapparatus and configuration is provided which uses a fracturing fluidstream of natural gas and proppant but no fracturing liquid. Fracturingwith a stream of natural gas containing only proppant can be beneficialin situations where any liquid is undesirable and proppant is requiredto maintain the created fracture system during production. This is oftenthe case for fracturing coal bed methane wells or low pressure shaleformations where liquid removal can be difficult. In this embodiment, anatural gas source (515) is one or more vessels containing either ofcompressed natural gas or liquefied natural gas. The natural gas source(515) is connected to a high pressure natural gas pump (517) via conduit(523) with valve (V45) for control of the natural gas feed. The highpressure natural gas pump (517) is a compressor applying gas compressionin the case of a CNG source and is a cryogenic pump and heater in thecase of a LNG source. The gaseous natural gas stream leaves the highpressure natural gas pump (517) via conduit (524). A proppant supply(512) with control valve (V25) intersects the conduit (524). Theproppant supply (512) is pressurized to match the discharge pressurefrom high pressure natural gas pump (517). Proppant flow from the supply(512) is gravity fed into conduit (524) with proppant additioncontrolled by valve (V25). The resulting natural gas slurry continuesalong conduit (524), through valve (V75) conduit (525) and into thewellhead (19). The gas stream and proppant then travels down thewellbore to create the hydraulic fracture in the subterranean reservoir.

Fifth Embodiment: Fracturing System for Injecting a Fracturing FluidMixture Comprising Natural Gas and a Base fluid without Proppant

According to a fifth embodiment and referring to FIG. 8, a fracturingapparatus is provided which uses a fracturing fluid mixture comprisingnatural gas and a base fluid that does not have any proppant.

Fracturing with such a fracturing fluid mixture can be beneficial insituations where a liquid portion is desired within the created fracturesystem and proppant is not needed to maintain the created fracturesystem during production. This is often the case for acid fracturingcarbonate formations where natural gas energized or foamed acid is usedto create and etch a fracture system. In this embodiment, the fracturingliquid tank (13) contains the desired liquid. Conduit (26) is used totransfer the liquid to a fracturing blender (614) where fracturingchemicals from chemical source (22) are also directed and mixed with theliquid. The discharge from the fracturing blender (614) passes through aconduit (650) as controlled by valve (V36) and is received by highpressure liquid pump (616). Discharge from high pressure liquid pump(616) is directed to a fracturing fluid mixer (618) along conduit (642),controllable by upstream valve (V56). The natural gas source (15) is oneor more vessels containing either of compressed natural gas or liquefiednatural gas. The natural gas source (15) is connected to the highpressure natural gas pump (17) via conduit (23) with valve (V4) forcontrol of the natural gas feed. The high pressure natural gas pump is acompressor applying gas compression in the case of a CNG source and is acryogenic pump and heater in the case of a LNG source. The gaseousnatural gas stream leaves the high pressure natural gas pump (17) viaconduit (24), through valve (V6) and into the natural gas stream slurrymixer (618) where it is combined with the liquid fracturing stream fromconduit (42). The mixed natural gas and liquid stream leaves the mixer(618) along conduit (625) and into wellhead (19). The mixed natural gasand liquid stream then travels down the wellbore to create the hydraulicfracture in the subterranean reservoir.

Sixth Embodiment: Fracturing System Having Natural Gas Venting andPurging Equipment

According to a sixth embodiment, the formation fracturing system canfurther include equipment for venting, purging, and/or isolating naturalgas and air from parts of the system (“venting, purging and isolationequipment”). Such equipment is beneficial to control the risksassociated with natural gas being a flammable high pressure gas source.The equipment can include use of a cryogenic inert fluid such asnitrogen, cooled to pre-cool the high pressure natural gas pump or otherequipment prior to introducing the natural gas. This eliminates the needto pre-cool the system using flammable natural gas and eliminates thenatural gas flaring otherwise needed. The inert fluid can also be usedto pressure test the fracturing system to identify any leaks orfailures, or permit any configuration or function testing of the system.

Also, the inert fluid can be used to substitute any natural gas sourceto quickly purge any residual natural gas, oxygen, or air before, duringor after fracturing treatment. In this purging operation, the inertfluid is injected through at least part of the system before or afterthe fracturing fluid is injected through the wellhead and until the atleast part of the system is in a non-flammable state. The purgingoperation is intended to purge the system components below a flammablelimit, such as the “Lower Explosive Limit” (LEL), which is the lowestconcentration (percentage) of a gas or a vapor in air capable ofproducing a flash of fire in presence of an ignition source (arc, flame,heat). In the event of a leakage or component failure during fracturingtreatment, the venting, purging and isolation equipment allows for thatcomponent to be isolated so that the remainder of the system isunaffected.

FIG. 9 shows an embodiment of the fracturing system having thefracturing fluid storage and supply equipment as shown in FIG. 1 withthe venting, purging and isolation equipment. The venting, purging andisolation equipment comprises a series of valves V12-V16 fluidly coupledto the natural gas and base fluid supply conduits 23, 24, 42, 50 in thesystem, an inert purging source 45 for purging components of the system(and optionally cryogenically cooling such components), a series ofinert gas supply conduits 46, 47 for delivering the inert gas to thenatural gas and base fluid supply conduits 23, 24, 42, 50 and ventingconduits 48, 49, 51 for venting gases from the supply conduits 23, 24,42, 50. A controller 58 (see FIG. 11) can also be provided to controlthe venting, purging and isolation operations.

Purging is carried out prior to introducing natural gas into the systemfrom valve (V4) through equipment and conduits to the wellhead valve(V7), i.e. supply conduit (23), NG pump (17), conduit (24), mixer (18)and conduit (25). In the present system, venting followed by purging iscarried out on all natural gas containing conduits and equipmentfollowing the fracturing treatment and prior to rigging out theequipment for mobilization. The venting and purging can potentiallyencompasses the system from valve (V5) and as far upstream as valve (V3)(wherein venting is accomplished via valve (V16) through conduit (51) toflare (20)) to address overpressure reverse migration, and from naturalgas source outlet valve (V4) through equipment and conduits to wellheadvalve (V7).

Instead of venting, the inert purging fluid and the purged contents canbe directed into the well. In an alternative embodiment, nitrogen or anysuitable inert gas can be used to purge the system equipment then bedirected into the well to fracture the formation, either alone or withthe natural gas.

Additionally, and in the case of an unplanned natural gas release due tocomponent failure, the failed component may be internally isolated andthe natural gas remaining in the isolated system components vented andpurged. For purging and venting a low pressure portion of the naturalgas system, the inert purging source (45) is connected via inert gassupply conduit (46) and inert gas supply valve (V12) to the natural gassupply conduit (23) after the natural gas source outlet valve (V4) andbefore the high pressure pump (17). This arrangement enables inert fluidto be delivered to the low pressure section of the natural gas supplyconduit 23. Further, venting conduit (48) with venting conduit (49) areattached to natural gas supply conduit (23) through venting valve (V14)which is located downstream of the natural gas source outlet valve (V4)and upstream the high pressure pump (17); this venting conduit (48) iscoupled to venting conduit (49) which in turn is coupled to flareconduit (20 a). This arrangement enables the inert fluid and natural gasto be vented from the natural gas supply conduit (23) and through flare(20).

For purging and venting a high pressure portion of the natural gassystem, the inert purging source (45) is connected to a high pressuresection of the natural gas supply conduit (24) (which is locateddownstream of the high pressure natural gas pump (17)) via inert fluidsupply conduit (47) and inert gas supply valve (V15). Additionally,venting conduit (49) with flare line conduit (20 a) is attached to thenatural gas supply conduit (24) downstream of the high pressure naturalgas pump (17) through venting valve (V13). This arrangement enables theinert gas to purge the natural gas supply conduit (24) and for gases tovent from this conduit (24) through flare (20).

For purging and venting a high pressure fracturing fluid portion of thesystem and the well, flare line conduit (20 a), through valve (V8) isconnected to fracturing fluid supply conduit (25) upstream valve (V7),and downstream mixer (18), base fluid supply conduit (42) and isolationvalves (V5) and (V6). This arrangement enables purging of conduit (25)by purging fluid from source (45) via conduit (47), through open valve(V15), through mixer (18) and into conduit (25); valve (V13), (V5), (V7)are closed. Also, this arrangement enables fluids in fracturing fluidsupply conduit (25) to vent through the flare 20 via valve V8 and flareline conduit 20 a.

Also, base fluid supply conduit (50) is coupled to flare (20) viaventing valve (V16) and venting conduit (51); this arrangement enablesfluids to be vented from the base fluid conduit to the flare 20, e.g. inthe event an internal leak occurs and natural gas enters the base fluidstorage and supply portion of the system.

The venting, purging and isolation equipment permits isolation, ventingand purging of the system as needed to make it safe under all reasonableconditions. As an example, should fracturing fluid mixer (18) experiencean unplanned release, the isolation valves (V5), (V6) and (V7) can beimmediately closed to isolate the release from other parts of thesystem. The source valves (V3) and (V4) are then closed and the valve(V8) is opened to direct all and any gas within the isolated portion ofthe failed system to the flare (20) and thereby control and eliminatethe release from the natural gas stream slurry mixer (18). As anotherexample, valve (V14) can be opened to vent contents enclosed withinconduits and equipment between valves (V4) and the high pressure naturalgas pump (17) through vent conduits (48), (49) and flare line conduit(20 a). Similarly, valve (13) can be opened to permit venting ofcontents enclosed within conduits and equipment between the highpressure natural gas pump (17) and valve (V6) through vent conduits (49)and flare line conduit (20 a).

Upon sufficient venting, purging can be initiated by opening valves(V12) and (V15) and directing purging fluid from inert purging source(45) through the inert gas supply conduits (46) and (47). Purge flow canbe directed as required through various paths in natural gas andfracturing fluid conduits (23), (24), (25) and venting conduits (48) and(49) to the flare line conduit (20 a) by manipulating valves (V12),(V15), (V13), (V14), (V6), (V5), (V8) and (V16), as needed, to vent andpurge the complete system.

The inert purging source (45) is comprised of storage for an inert fluidsuitable for purging with a device suitable to move the purging fluidthrough the system. The purging fluid, in one embodiment, is an inertgas such as carbon dioxide or nitrogen and can be stored either as acryogenic liquid or in a pressurized gas phase. It is possible tocomplete purging with the inert fluid in gaseous phase, but in somecases and/or in later processes such as system cooling, the inert fluidmay be employed in liquid phase. Dependent upon the choice of inertfluid and its phase, moving the purging fluid through the system will beaccomplished by any of a control valve, pump or pump and heater, whichin one embodiment are not shown and contained within inert purgingsource (45), and which in another embodiment can be existing equipment

The aforementioned configuration of venting purging and isolationequipment and method for venting, purging and isolation using suchequipment relates specifically to the fracturing system described inFIG. 1. However, such equipment can be readily adapted for otherfracturing systems such as those shown in FIGS. 2, 3, 6, 7 and 8. Whenusing LNG as the source of natural gas as illustrated in the FIG. 3embodiment, the inert purging source (45) may be liquid nitrogen and thenatural gas fracturing pump (229) is cooled to cryogenic temperatures,purged and pressure tested using nitrogen. In such an embodiment, thehazards encountered with completing these steps using LNG can be reducedor eliminated altogether. The liquid nitrogen is withdrawn from source(45) through line (46) to the natural gas fracturing pump (229). Thenatural gas fracturing pump's cryogenic internal components are floodedwith the liquid nitrogen which vaporizes upon contact with the warmcomponents. The created vapor is vented to atmosphere through flare lineconduit (20) until the internals are sufficiently cooled such that theliquid nitrogen no longer vaporizes.

Referring to FIG. 11, operation of the fracturing system including thepurging, venting and isolation equipment is controlled by a controller(58). This controller (58) has a memory programmed to control theoperation of at least some components within the system. The controller(58) may communicate with components in the system by direct connectionor wireless connection to the various components. For example,fracturing blender (814), high pressure natural gas pump (817) and highpressure slurry pump (816) may be remotely controlled. The valves (V1)through (V16) may also be remotely controlled. Remote control capabilitypermits ready and reliable control of the operation from a central pointplus allows control of the system during normal operations, and inparticular an emergency, without exposing personnel to hazards. Controlof the components is directed by either the operator of the system via auser interface (59) or through software containing algorithms stored onthe memory of the controller and developed to direct the components tocomplete the task in a suitable manner. The controller is any suitableprocess control system and may include control inputs from operatorpanels or a computer. Similar control capability is applicable to otherdescribed configurations and other components as required.

For example, the controller (58) is connected to and controls theoperation of the feed valve (V4) and the high pressure natural gas pump(817) thereby controlling the supply of pressurized natural gas from itssource (815) to the natural gas stream slurry mixer (18). Concurrently,controller (58) is connected to and controls the operation of thefracturing liquid control valve (V1) to regulate flow from thefracturing liquid tank (813), the proppant supply valve (V2) to regulateflow from proppant supply (812), the chemical source (822) and thefracturing blender (814) in order to supply a properly constructedliquid slurry to the high pressure slurry pump (816). Simultaneouscontrol functions continue with controller (58) connected to andcontrolling high pressure slurry pump (816). Controller (58) furtherensures a properly proportioned mixed natural gas and liquid slurrystream is created by controlling the relative supply of the natural gasfracturing stream compared to the liquid slurry stream by control of thehigh pressure slurry pump (816) and the high pressure natural gas pump(814).

The controller (58) is also connected to valves (V3), (V5), (V6), (V7),(V8), (V10), (V11), (V12), (V13), (V14), (V15) and (V16) and inertpurging source (845) to control the venting, purging an isolationoperations and to monitor the condition of system components. In thisregard, the controller memory can have stored on it instructions tocarry out the venting, purging and isolation protocols as describedabove.

FIG. 16 is another schematic illustrating an additional embodiment of aformation fracturing system having venting, purging, and isolationequipment. The natural gas mix fracturing system comprises at least anLNG storage tank facility (L1, L2), an LNG/LN₂ manifold trailer (2), anLNG/LN₂ pump assembly (3), a liquid fracturing system (4), a natural gasslurry stream mixer (5) coupled to a well (6), and a gas system flare(SF1). A wellhead flare (SF2) may be optionally added to vent gases fromthe well (6). Although liquefied nitrogen gas (LN₂) is used as thepurging and cooling fluid in this embodiment, other embodiments caninclude other inert or cryogenic gases as appropriate.

The components above are all interconnected by a plurality of conduits(G1 to G8, N1 to N5), flare lines (F2 to F4) and valves (V1 to V50)which permit the controlled travel of both LNG and LN₂ throughout thesystem in order to efficiently and effectively isolate, vent, purge,cool, pressurize, and/or test the system as required, either before,during, or after a fracturing process. Centrifugal pumps (P1, P2, P3)provide flow of LNG and/or LN₂ within the system as required for a givenoperation.

Each LNG storage tank facility (L1, L2) comprises an LNG storage tank(T1, T2), and manual valves (V3, V4) and valves (V13, V14) that permitoutflow of LNG through conduits (G7, G8) to the inlet manifold (9) ofthe LNG/LN₂ manifold trailer (2). Valves (V18, V19) permit inflow of LN₂or any other suitable inert cryogenic gas from conduit (N2) to purgeeach storage tank facility (L1, L2) and coupled natural gas conduits(G7, G8). The LNG storage tank facilities (L1, L2) can also have inletvalves coupled to flare line (F2) to capture any inflow of residual LNGto maintain pressure within LNG tanks (T1, T2), and prevent unnecessaryventing of flammable LNG to the atmosphere.

The LNG/LN₂ manifold trailer (2) manages and coordinates the flow ofboth LNG and LN₂ throughout the natural gas mix fracturing system, andcomprises liquefied nitrogen source (T4), inlet manifold (9), anddischarge manifold (10). The inlet manifold (9) comprises a plurality ofvalves (V24 to V28). Each input of the inlet manifold valves (V24 toV28) are coupled to a conduit (G7-G8) to accept an individual flow ofLNG or LN₂ from each storage tank facility (L1, L2, other tanks forcoupling to V26-V28 not shown). The outputs of the inlet manifold valves(V24 to V28) are all coupled to conduit G1 to provide the dischargemanifold (10) with a collective flow input LNG or LN₂. Conduit G1 isalso coupled to flare line (F2) through valve (V51) for venting of anyresidual gas to the system flare (SF1). The discharge manifold (10)comprises a plurality of valves (V38 to V40). The inputs of thedischarge manifold valves (V37 to V40) are all coupled to conduit (G2)to accept an inflow of LNG from conduit (G1) or LN₂ from conduit (N6).Each output from the discharge manifold valves (V37 to V40) is coupledto an individual LNG/LN₂ pump assembly (3) (other pump assembliescoupled to V38 to V40 not shown).

The LNG/LN₂ pump assembly (3) provides a pressurized and heated flow ofLNG or LN₂ to the natural gas slurry stream mixer (5). LNG/LN₂ pumpassembly (3) comprises a charge pump (P3) which feeds the Triplex Pump(P4) with LNG or LN₂. Triplex Pump (P4) then pressurizes the LNG or LN₂from conduit (G6), and/or LN₂ from conduit (N4) to a target pressure.Heat Exchangers (EX5, EX6) then operate to heat the discharge from theTriplex Pump (P4) to a target temperature before it reaches the naturalgas slurry stream mixer (5).

A detailed discussion of each of the isolation, venting, purging,cooling, pressure testing, operational testing, and displacementoperations with the above configuration now follows.

Isolation: In the event of an unplanned natural gas leak or componentfailure, the system is configured to isolate, vent, and purge theaffected area. LNG storage tank valves (V13, V14) are closed to preventfurther flow of LNG into the system. Then, any conduit (G1 to G8, N1 toN5) or component can be specifically isolated by closing the adjacentvalves of a given conduit. For example, potential leakage in conduits(G7, G8) can be isolated by closing valves (V13, V14) and valves(V24-V28). Pump assembly (3) can be isolated by closing valves (V42,V43, V44), and output conduit (G3) isolated by additionally closingvalves (V45, V47). This configuration allows for the precise systematicisolation of any conduit or component within the system as required. Indrastic situations, there may be complete isolation of all conduits andcomponents by closing all valves in the system. Thus the interconnectionof valves, conduits, and components cooperate to provide a safe lowvolume release system that can to isolate, vent, and purge any affectedarea.

Venting: Venting is preferably performed upon isolation in order tosafely direct any residual gases to system flare (SF1). Valve operationcan be systematically coordinated in order to vent a specific isolatedarea through one of the flare lines (F2, F3, F4) to system flare (SF1).Essentially, a flow path is created by the opening and closing ofspecific valves in order to direct gases in a certain isolated areatowards one of the flare lines (F2, F3, F4). For example, residual gasin conduit (G1) can be vented through flare line F2 by closing valves(V24-V28) and (V34), and opening valve (V51). Conduit (G2) can be ventedthrough flare line (F3) by closing valves (V34, V37-V40, V49), andopening valve (V41). Conduits (G3, G4) can be vented by closing valves(V44, V47) and opening valve (V45). This configuration therefore allowsfor the safe, effective, and efficient venting of residual gases withinany conduit or system component.

In some embodiments, venting can be assisted through operation of heatexchangers (EX5, EX6) to help expand and vaporize any residual fluidsthrough conduits (G6 and F4) to system flare (SF1).

Purging: Purging can be performed after isolation and venting in orderto remove any remaining oxygen or contaminants within the system.Although liquefied nitrogen gas (LN₂) is used as the purging fluid inthis embodiment, other embodiments can include any suitable other inertgas, such as helium, neon, argon, kyrpton and carbon dioxide or mixturesthereof. Purging of specific conduits or components can be achieved bydirecting a flow of LN₂ from liquefied nitrogen source (T4) towardsthrough the target conduit or component, and then to one of flare lines(F2, F3, F4) to system flare (SF1). For example, LNG storage tankfacility outlets (L1, L2) are purged through LN₂ flow through conduits(N1, N2, and N3) and valve (V23), where centrifugal pump (P1) assists inproviding the required flow. Residual gases at the LNG storage tankoutlets or in conduits (G7, G8) can also be optionally vented throughopening the appropriate inlet manifold valves (V24, V25) and flare valve(V51). From N3 nitrogen flow is directed to conduits (G7, G8) into inletmanifold (9) through valves (V24, V25) and optionally vented throughvalve (V51) to venting conduit (F2) or continued to flow through conduit(G1) through valve (V34), through conduit (G2), through valve (V41) thenvented through venting conduit (F3).

Conduit (G2) is purged through LN₂ flow from conduit (N6) or throughconduit (G1) valve (V34) and centrifugal pump (P2), and is ventedthrough valve (V41) to flare line (F3). In this manner, a flow of LN₂ orother inert gas can be sent to a specific target area or component andthen safely vented to system flare (SF1). Alternatively, simultaneouspurging of the entire system can also be performed by appropriate valvecontrol.

Cooling: Cooling is performed in order to lower the system to operatingtemperature in preparation of handling cryogenic LNG. As describedabove, LNG as applied has a working temperature of approximately −162°C. (−260° F.). The use of LN₂ or another inert cryogenic fluid to coolthe system precludes the use of flammable LNG, which could createunnecessary safety issues. LN₂ is provided by liquefied nitrogen source(T4) through valve (V32) and conduit (N1). Centrifugal pumps (P1, P2,P3) can be optionally operated to assist in the movement of LN₂throughout the system. LNG storage tank outlet valves (V13, V14) areclosed to prevent any outflow of LNG. In the same manner as describedabove for purging, the system can target specific conduits or componentsfor cooling by directing flow of LN₂ from liquefied nitrogen source (T4)towards the target conduit or component through the selected use ofvalves.

Alternatively, the entire system can be cooled simultaneously throughappropriate valve control. Cooling and purging may occur simultaneouslyin the same process step, with any remaining fluid optionally vented toone of flare lines (F2, F3, F4) to system flare (SF1). For example,LNG/LN₂ pump assembly (3) is cooled by opening valve (V43) to accept aflow of LN₂ from conduit (G6), through a charge pump (P3) and TriplexPump (P4). LN₂ circulation loops are also provided throughout the systemin order achieve or maintain cool down. Once the system is cooled, LN2circulation is maintained to prevent heating and possible vaporization.The ambient heater and valve system to the right of valve (V32) on LN2tank (T4) is used to maintain pressure in the LN2 tank T4. Using theabove example, with valve (V44) closed, a circulation loop is createdwith the inflow LN₂ which travels back to liquefied nitrogen source (T4)through conduits (N4, N5) and valves (V42, V30, V31). This circuit isthe cool down loop for circulation of LN2 from the tank through conduit(N3) and the complete cryogenic system to the pumps, then back to thetank. Circulation of LN₂ can thus be continued in this manner until suchtime as the piping, assemblies, and components are flooded with nitrogenand cooled to an acceptable LNG handling temperature. In oneapplication, LN2 is maintained within the system, the operationaltesting is maintained for a short period at the beginning of thefracturing treatment, then LNG is applied with the nitrogen displacedinto the well as into a very small part of the fracturing formation.

Pressure Testing: Pressure testing is performed to determine anypotential leaks or failures within the system prior to LNG operations.Pressure testing can be performed for a specific conduit or component,or for the entire system, as desired. The target area is flooded withLN₂, then isolated, and then monitored for any pressure drops that mayindicate a leakage. Alternatively, the entire system can be pressuretested by closing valves (V45, V47), and operating pumps (P1, P2, P3) topressure and feed LN₂ to Triplex pump (P4). Upon completion, anappropriate venting procedure can be performed to reduce LN₂ pressureand proceed with the next operation. The pressure test will typicallyfollow cool down as the system must be cooled for either of LN2 (−186 C)or LNG (−162 C).

Displacement: After completion of the well fracturing treatment, LNGwithin the system can be replaced with LN₂ in order to remove andsufficiently purge the system of any LNG or natural gas. LN₂ can also bepumped into the wellbore to displace any flammable natural gas to leaveit in a safe condition. Alternatively, LN₂ can be used during thefracturing treatment to purge the parts of the system then be pumpedinto the wellbore to contribute to the fracturing operation along withthe natural gas in the wellbore.

LN₂ displacement can closely follow the procedure described above forLN₂ purging. Alternatively, system displacement can be effected by firstclosing LNG storage tank facility valves (V13, V14) to prevent anyadditional outflow of LNG, and drawing LN₂ into the system throughconduits (G7, G8), then the inlet manifold (9), then the dischargemanifold (10), then the LNG/LN₂ pump assembly (3), then to the naturalgas slurry stream mixer (5), and finally to the well (6). Residualnatural gas from the fracturing process can be recovered or optionallyvented through flare lines (F2, F3, F4) during or after displacement. Inthis manner the complete system is purged of natural gas from the LNGStorage Tanks (T1), (T2) through to the wellhead (6). Wellbore valve(V50) can be closed to isolate the system from the wellbore (6) andother equipment in preparation for the next fracturing treatment or fordisassembly for mobilization to a different location for treatments onother wellbores. Activities such as re-filling LNG tanks, completingequipment inspection and maintenance or wellbore preparations can beundertaken during this time.

Method of Operation

FIG. 15 is a flow schematic illustrating a method of forming afracturing fluid mixture that contains natural gas as a gas phase insufficient quantity to desirably alter the characteristics of thefracturing treatment.

At step (80), a sufficient quantity of natural gas is made available tocomplete the fracturing treatment. Fracturing treatments can consumeconsiderable quantities of fracturing fluids with common volumes over500 m³ (130,000 gal) with unconventional fracturing consuming volumes inthe order of 4,000 m³ (1,000,000 gal). Applying any reasonable quantityof natural gas to the fracturing treatment can consume anywhere from50,000 sm³ (1.5 MMscf) to 300,000 sm³ (10 MMscf) of gas within a 4 to 6hour pumping period. To meet the volume and rate requirement, thenatural gas is stored awaiting pumping for most applications. Storage ofnatural gas can be completed by either holding it in pressured vesselsor by liquefying for storage in cryogenic vessels. Efficient storage ofnatural gas in pressured vessels is achieved at the highest possiblepressure which is typically less than 30 MPa (4,400 psi), holdingapproximately 10,000 sm³ (0.4 MMscf) in each unit. Effective storage ofthese quantities even at maximum pressures would require severalpressurized vessels with numerous connections between tanks and pumpingequipment at the elevated storage pressures. Alternatively, LNG can bestored in LNG tanks on-site which permits considerable volumes to bestored efficiently and at pressures as low as atmospheric. As acryogenic liquid one unit volume of LNG contains approximately sixhundred volumes of gas at atmospheric conditions. In a single LNGstorage vessel containing 60 m³ (16,000 gal) of LNG, an equivalent of36,000 sm³ (1.2 MMscf) is stored. A large treatment would requireapproximately 10 LNG storage tanks compared to over 30 pressured naturalgas tanks. The use of LNG eliminates the issues found with gas phasestorage; the multitude of high pressure vessels and piping needed todraw the natural gas from the pressure vessels result in a very complexand potentially hazardous system.

Step (81) of FIG. 15 refers to processing the natural gas to thefracturing pressure in sufficient quantity. Fracturing pressures areoften in the range of 35 MPa (5,000 psi) to 70 MPa (10,000 psi), whilethe natural gas rate is usually from 400 sm³/min (15,000 scf/min) to1,200 sm³/min (40,000 scf/min). Pressuring the compressed natural gas tofracturing pressures requires gas phase compressors of some form.Alternatively, pressuring natural gas to the extreme pressuresencountered in hydraulic fracturing in liquid form as LNG isexceptionally efficient. As a liquid the volumetric rates are muchreduced and incompressible as compared to gaseous natural gas,compression heating is eliminated and equipment size and numbersdrastically reduced. The cryogenic natural gas liquid is directlypressured to the fracturing pressure by a single pump, and then simplyheated to the application temperature. For an upper-end fracturing gasrate at pressure, LNG is pumped at approximately 2 m³/min (500 gal/min)of liquid yielding a gas rate in excess of 1,500,000 sm³/day (60MMscf/day) through 8 units of rate to 160 sm³/min each. This smaller andsimpler equipment configuration significantly reduces the complexity ofthe operation removing many of the costs and hazards which would bepresent with compressed gas techniques.

At step (82), the natural gas stream is combined with the base fluidstream. As disclosed previously, the mixer (18) can be used to combinethe two streams in a high pressure treating line prior to or at thewellhead; this approach allows easy handling of the separate streamswithout disruption to typical fracturing operations, completes the taskwithout modification to the well and is a simple and effective way toaccomplish mixing the natural gas and liquid-slurry streams. Thisresults in a simple, effective and reliable method for mixing thesecomponents.

Alternatively, the base fluid stream can be combined with the naturalgas stream in a low-pressure process or within the wellbore atfracturing pressure. The natural gas is injected down one conduit withinthe wellbore and the liquid-slurry down another with the two streamscombining at some point in the wellbore. In these cases, some type of aspecialized wellhead or wellbore configuration in the form of anadditional tubular and a common space is provided where the two streamscan meet.

In one embodiment, step 80 includes providing a supply of liquefiednatural gas stored in cryogenic vessels, step 81 includes employing acryogenic pump to process the liquefied natural gas to fracturingpressure and supply it at a suitable rate and employing a heat exchangerto heat the liquid natural gas to the application temperature, and step82 includes combining the natural gas with a base fluid with mixer (18)to obtain a resultant fracturing fluid prior to passing the resultantfracturing fluid to the wellhead.

EXAMPLES

The following examples are provided for illustration only and are notintended to limit the scope of the disclosure or claims.

Example 1

FIG. 12 is a schematic of an embodiment showing a configuration wherethe natural gas fracturing system components mounted on a series ofmobile trucks. The mobile trucks transport the equipment for creatingand pressurizing the liquid based fracturing slurry; the fracturingblender (14), the chemical source (22), the high pressure pump (16),plus transport the equipment for storing, pressurizing and heating theliquefied natural gas; the LNG storage tanks (215) and LNG fracturingpumpers (229) and the ancillary equipment; the inert purging source (45)and the controller (58).

The configuration and apparatus on any one unit can be altered or theequipment may be temporarily or permanently mounted as desired. Thisembodiment displays multiple LNG storage tanks (215) connected tomultiple LNG fracturing pumpers (229). Pre-treatment pressure testing ofthe liquid and proppant pumping system, components (14), (16), (22) andconduits (26), (50), (42), (25) is completed with the fracturing liquid(13) or other suitable liquid as desired. Liquid supply (13), proppantaddition (12), chemical addition (22), proppant blending (14) and liquidslurry pressurization (16) are completed with the equipment componentsas shown and delivered to liquid-slurry conduit treating line (42). TheLNG storage tanks are connected to conduit (62) to allow venting to theflare (20) through flare line (20 a) until beginning the treatment whenvalve (V18) is closed. Conduit (46) connects the inert gas source (45)to the inlet conduit (23) for supply of cryogenic nitrogen to the LNGfracturing pumps for cryogenic cool down, pre-treatment purging andpressure testing of the LNG supply plumbing (23), pumping and heatingequipment (229) and the natural gas conduit treating line (24). Inertgas source (45) is also connected to natural gas treating line conduit(24) to permit venting or purging with gaseous nitrogen of the highpressure system if required.

Purged or vented natural gas can be directed to the separator (60) andto flare (20) via either vent conduit (49) with valve (V13) or conduit(20 a) with valve (V8). Similarly, the low pressure conduit (23) can bepurged with gaseous nitrogen or vented through conduit (46) via ventconduit (48) to separator (60) and onward to flare (20) via valve (V14).Cool down and purging are completed with cryogenic nitrogen directedthrough conduits (46) and (23) to the inlet of the LNG fracturingpumpers (229). In turn, each of the LNG fracturing pumpers (229) isflooded with the liquid nitrogen until sufficiently cooled to accept LNGwithout vaporization. Vaporized nitrogen is released from the LNGfracturing pumpers (229) through natural gas treating line conduit (24),value (V6), flare conduit (20 a) to flare (20). Upon establishing cooldown in each LNG fracturing pumper (229), the flare valve (V8) is closedand nitrogen pumped and heated by the LNG fracturing units to achieve ahigh-pressure pressure test of the system with nitrogen. The base fluidsupply system is isolated throughout this process by closed valve (V5).Upon completing the pressure test of the natural gas pumping system,valve (V8) is opened, pressure is released, the nitrogen source isisolated with valve (V12), and the LNG source valves (V4) are opened topermit flow of LNG into the system. The LNG fracturing pumpers (229) areoperated to displace nitrogen from the system with LNG in preparation tobegin the fracture treatment. Discharge from the LNG fracturing pumpersis directed through treating line conduit (24) to flare line (20 a)until natural gas is observed at the flare. Valve (V8) is then closed,valves (V5), (V6) and (V7) opened and the fracturing treatment started.LNG is drawn from tanks (215) through conduit (23), into LNG fracturingpumpers (229) for pressurization and heating with discharge throughnatural gas conduit treating line (24). The liquid-slurry base fluidstream from conduit (42) mixes with the gaseous natural gas stream fromconduit (24) within fracturing fluid mixer (18) and is directed to thewell (19) through treating line conduit (25).

Example 2

Using apparatus such as that of FIG. 3, FIG. 9 and FIG. 11, an example,proposed application of the system is given to illustrate the method.The objective is to stimulate a gas bearing reservoir at a depth of 2500m with a 100 tonnes of proppant using a 75% quality slick water foamednatural gas fracturing treatment. The well has perforations at a depthof 2500 m with 114.3 mm casing, no tubing and a bottom hole temperatureof 90° C. In this example, the natural gas source is selected asliquefied natural gas (LNG) and the relevant apparatus and configurationof FIG. 3. is applied.

TABLE 1 Natural Gas Frac 100 tonne Natural Gas Foamed Slick Water FracFluid: 75% Quality Foamed Slick Water with Natural Gas Proppant:  10tonne 50/140 mesh sand  90 tonne  30/50 mesh sand Treating Rate: 5.0m3/min Injection Calculations Depth to Top Perforation: 2.510.5 m FracGradient: 18.0 kPa/m Bottom Hole Fracturing Pressure 45.189 kPa SurfaceInjection Pressure (1) 56.267 kPa Bottom Hole Temperature 90 degC. WaterDensity 1.000 kg/m3 Blender Rate 1.3 m3/min Required Liquid Pump Power1.172 kW Natural Gas Specific Gravity (2) 212.3 kg/m3 Natural Gas VolumeFactor (2) 312.0 m3/sm3 Natural Gas Rate 1170 sm3/min Required LNGFracturing Pumps 7 units a 160 sm3/min each Wellbore Volume to TopPerforation Interval ID Capacity Volume Tubing   0.0 m  0.0 mm  0.00000m3/m  0.0 m3 Casing 2510.5 m 95.0 mm 0.007088 m3/m 17.8 m3 Total 2510.5m 17.8 m3 Underflush  0.5 m3 Flush Volume (DO NOT 17.3 m3 OVERFLUSH) (1)Calculated for the compresible foam column at rate with based fluidrheology for slick water (2) At bottom hole fracturing pressure

Equipment is mobilized to the well site and spotted. For this treatment,specific equipment include one of a high pressure pumper (16) atcapability to 1,127 kW, seven of 160 sm3/min LNG fracturing pumpers(229) to a rate of 1,170 sm3/min, two of 64 m3 liquid tanks (13) andthree of 60 m3 LNG tanks (215). An inert purging source is supplied withliquid nitrogen. Chemical source (22) is provided to apply twoadditives. A pre-rigging safety meeting is conducted detailing sitehazards, location of safety equipment, safety areas, and the siteevacuation plan. The equipment is rigged in following the configurationspecified in FIG. 9 and FIG. 11 including the adaptation presented inFIG. 3 for a LNG source fracture treatment. The liquid tanks (13) areloaded with 119 m3 of water and 168 m3 of LNG is provided in the LNGstorage tanks (215). The proppant supply vessel (12) is loaded with 10tonnes of 50/140 mesh sand and 90 tonnes of 30/50 mesh sand. Thechemical source (22) is loaded with a friction reducer to 107 L volumeand a foaming surfactant to 308 L volume.

A pressure test is then conducted on the system. Typical to ananticipated injection pressure approaching 57,000 kPa, the pressure testof the high pressure components is completed to a pressure of 69,000kPa. Valve manipulation and operation of the apparatus in completedunder the control of controller (58). Pressure testing for the liquidportion of the system, from fracturing liquid tanks outlet valve (V1) tothe wellhead control treating valve (V7), is completed with water fromthe fracturing liquid tanks (13). To initiate the pressure test valves(V1), (V3), (V6), (V7), (V8), (V10) and (V16) are closed. Valve (V1) isthen opened to release water to the fracturing blender (14). Thefracturing blender is operated to circulate water at operating pressure,typically less than 700 kPa (100 psi) and confirmed free of leaks. Valve(V3) is then opened to feed water to the high pressure slurry pump (16).A bleed port (not shown) in the treating line (42), before valve (V5) isopened to permit flow through the high pressure pump. The high pressurepump (16) is slowly rotated to capture water feed and when a full waterstream escapes from the bleed port, the pump is fully primed and theport is closed. All personnel clear the area and additional power isapplied to the high pressure pump (16) to pressure the pump itself plusthe conduit (42) and (25) treating lines, the valves (V5), (V6), (V7)and (V18) and the natural gas stream slurry mixer (18) to the requiredtest pressure of 69,000 kPa. When at test pressure, the high pressureslurry pump (16) is then stopped and the tested components checked forcompliance. Pressure is then released from the liquid line and theliquid system test is complete.

Preparation and testing of the natural gas system is then begun.Pressure testing is completed on all components from valve (V42) throughvalve (V6) including conduit (32) vapor feed line to the LNG source(215) and nitrogen will be used to pressure test, purge and cool downthe natural gas conveying system. To initiate the pressure test, valves(V4), (V6), (V11), (V12), (V13), (V14) and (V15) are closed. Valve (V12)is then opened and the inert purging source is operated to pump andvaporize nitrogen into the system to a pressure of 2 MPa (300 psi) tocomplete a low-pressure pressure test. Operation of the inert purgingsource is then stopped and conduit (23), valves (V4), (V6), (V12),(V13), (V14) and (V15) are checked for leaks. Upon confirmation thatthere are no leaks, pressure is bled from the system through to flare(V20) through conduit vent line (48) by opening valve (V14). Valve (V14)is then closed and LNG source (15) is operated to release liquidnitrogen to the LNG fracturing pumper (229) through conduit (46) intoconduit (23). The LNG fracturing pump (229) is operated and cryogenicinternal components are flooded with the liquid nitrogen which vaporizesupon contact with the warm components. The created nitrogen vapor isvented to atmosphere through flare line conduit (20) until the internalsare sufficiently cooled such that the liquid nitrogen no longervaporizes. Operation of the LNG fracturing pump is (229) is then stoppedand conduit (23), valves (V42), (V14) and (V12) are checked for leaks.The LNG fracturing pump (229) is then operated to pressure and vaporizethe liquid nitrogen with vapor directed to the flare for purging all airfrom the test system. A complete purge can be determined by placing anoxygen meter in the purge stream or by pumping the volumetricrequirement to purge with a safety factor. Upon completing the purge,the LNG fracturing pump (229) is then stopped and valve (V6) is closed.All personnel clear the area and additional power is applied to the LNGfracturing pump (229) to pressure up the pump itself plus the conduit(24) treating line and the valves (V6), (V13) and (V15) to the requiredtest pressure of 69,000 kPa. When at test pressure, the LNG fracturingpump (229) is then stopped and the tested components checked for leaks.At this time, vapor feed line conduit (32) is tested by opening valve(V11) to permit nitrogen pressure into the conduit. The vapor inletvalve (V22) to the LNG source tank (15) remains closed for the test toavoid pressuring of the LNG tank with nitrogen. Valve (V11) ismanipulated to pressure test conduit (32) only to the pressure reliefsetting of the LNG source tank (15). Inert purging source (45) is thenisolated from the system by closing valve (V12). Pressure is thenreleased from the liquid line to the flare and the purge and pressuretest are complete. The LNG tank source control valve (V42) is thenopened and the valve (V6) opened to again allow flow to the flare lineconduit (20).

The LNG fracturing pump (229) is then operated with an LNG feed todisplace liquid nitrogen from the conduit (23) through the pump andconduits (24) and (25) to the flare line conduit (20) with natural gas.This ensures an LNG feed has been established to the LNG fracturing pumpprior to beginning operations. The flare system (20) is tested at thistime.

A pre-treatment safety and operations meeting is then held with allpersonnel. Site hazards are reviewed including location of safetyequipment, safety areas, and the site evacuation plan. The operationmeeting details the treatment procedures, equipment responsibilities,pressure maximums and any other treatment details specific to this wellor fracture treatment operation.

The natural gas source (215), usually provided at or near atmosphericpressure, is pre-pressured to 350 kPa (50 psig) using the LNG FracturingPump (229) through vapor line conduit (232) with valves (V12) and (V22)opened to ensure adequate feed pressure during the fracturing operation.Once the system has been pressure tested for safety and the LNG source(215) pressured, under control of the controller (58), flare valve (V8)and natural gas line valve (V6) are closed. The liquid line valve (V5)and the well control valve (V7) are opened.

Fracture pumping operations are now begun according to the exampleFracturing Treatment Program of Table 2. Equipment operation and valvemanipulation is completed using controller (58) throughout the processensuring personnel do not enter the high pressure hazard area during thetreatment. The liquid fracturing fluid control valve (V1) is opened andfracturing blender (14) operated with high pressure slurry pump (16) tobegin a liquid feed rate into the well at 0.5 m3/min to begin the holefill. Chemicals, friction reducer and foaming surfactant, are added tothe liquid stream at the required proportions under the control ofcontroller (58). Properties of the created natural gas foam can becontrolled in a number of ways. Altering the foam quality, proportion ofnatural gas to total volume, will change the density and viscosity ofthe resulting mixture. Altering the strength or concentration of thefoaming surfactant will alter the gas bubble size and change theresulting viscosity of the foam. Changing the viscosity of the liquidphase by adding a viscosifier will alter the resulting viscosity of thefoam. Valve (V6) is opened and LNG fracturing pump (229) is operated tobegin injection of gaseous natural gas into the liquid stream. Theliquid stream pumping is begun and established before the natural gasstream pump is operated to ensure natural gas is not inadvertently fedback to the liquid system. Controller (58) monitors the liquid feed rateand the natural gas addition rate via individual flow meters or pumpstroke counters and adjusts the LNG fracturing pump (229) to maintainthe correct natural gas to liquid ratio for a 75% quality foam. With ahole fill rate specified in this instance at a total rate of 2.0 m3/minfoam, the LNG fracturing pump (229) is regulated to a rate of 468sm3/min. This requires a LNG rate from the storage source (215) of 0.78m3/min. Pumping to fill the wellbore is continued until 17.8 m3 of foamis pumped. The wellbore from surface to the perforations is now full ofnatural gas foam. Pumping is continued and pressure within the wellborerises as additional volume is pumped until the formation break downpressure is reached and the underground fracture initiated. The hole isnow filled, the fracture initiated and a feed rate into the undergroundfracture established. Total rate is then increased to the desiredtreating rate of 5.0 m3/min and the foamed pad injection begun. A liquidrate of 1.25 m3/min and a natural gas rate of 1170 sm3/min, requiring afeed rate of 1.96 m3/min of LNG, generate a total rate of 5.0 m3/min atthe anticipated underground fracturing pressure of 45,189 kPa. As acompressible gas, the required natural gas rate at surface is based uponthe down hole fracturing pressure and the target total rate. Thecompression of natural gas at 45,189 kPa and 90° C. is such that 312 sm3of natural gas is required to create one m3 of space. In the event thatthe bottom fracturing pressure varies from that anticipated, thecontroller (58) adjusts the surface natural gas rate to maintain theproper down hole rate for a 75% quality foam. The natural gas foamed padis continued until a total foam volume of 40 m3, 10 m3 of water at 75%quality, is pumped into the wellbore. The pad serves to extend and widenthe underground fracture sufficiently to accept the proppant containedwithin the treatment steps following.

TABLE 2 Fracturing Treatment Program Fracturing Treatment Program - 100tonne Natural Gas Foamed Slick Water Frac Proppant 1 10 tonne 40/150mesh sand Density 1 2650 kg/m3 Hole Volume 17.8 m3 Proppant 2 90 tonne30/50 mesh sand Density 2 2650 kg/m3 Underflush 0.5 m3 Proppant Total100 tonne Bottom Hole Fracturing Pressure = 45,189 kPa Total Rate 5.0m3/min Bottom Hole Temperature = 90 deg C. Foam Quality 75% Natural GasVol Factor = 312 sm3/m3 Slurry Liquid Proppant Blender Liquid LiquidCumulative Blender Proppant Cumulative Rate Rate Volume Liquid VolumeConcentration Stage Proppant Stage Description (m3/min) (m3/min) (m3)(m3) (kgSA/m3 liq) (tonne) (tonne) Fill Hole 0.50 0.5 4.5 Pad 1.25 1.2510.0 10.0 Start 50/140 sand 1.25 1.22 4.0 14.0 250 1.0 1.0 Increaseconcentration 1.25 1.19 6.0 20.0 500 3.0 4.0 Increase concentration 1.251.17 8.0 28.0 750 6.0 10.0 Start 30/50 sand 1.25 1.17 8.0 36.0 750 6.016.0 Increase concentration 1.25 1.14 8.0 44.0 1000 8.0 24.0 Increaseconcentration 1.25 1.12 20.0 64.0 1250 25.0 49.0 Increase concentration1.25 1.10 34.0 98.0 1500 51.0 100.0 Flush treatment 1.25 1.25 4.3 102.3Natural Gas Downhole Conditions Nat'l Gas Nat'l Gas Cumulative TotalFoam Rate Stage Volume Nat'l Gas Rate Conc @ Perfs Quality StageDescription (sm3/min) (sm3) (sm3) (m3/min) (kgSA/m3 foam) (—) Fill Hole468 4165 4165 2.00 75.0% Pad 1170 9360 13525 5.00 0 75.0% Start 50/140sand 1143 3744 17269 5.00 63 75.0% Increase concentration 1117 561622885 5.00 125 75.0% Increase concentration 1093 7488 30373 5.00 18875.0% Start 30/50 sand 1093 7488 37861 5.00 188 75.0% Increaseconcentration 1069 7488 45349 5.00 250 75.0% Increase concentration 104718720 64069 5.00 313 75.0% Increase concentration 1025 31824 95893 5.00375 75.0% Flush treatment 1170 4048 99941 5.00 0 75.0% Treatment FluidRequirements Fill Mix Losses and Fluid Hole Pad Proppant Flush TankBottoms Total Natural Gas (sm3) 4,165 4,165 82,368 4,048 8,955 103,702sm3 LNG (m3) 7.0 7.0 138.0 6.8 15.0 174 m3 Water 4.5 10.0 88.0 4.3 12.0119 m3 Requires: LNG 3 tanks @ 60 m3 each Water 2 tanks @ 64 m3 eachChemical Addition Schedule Add to water portion only Mix Tank Fill HolePad Proppant Flush Bottoms Fluid Conc. Conc. Conc. Conc. Conc. TotalContinuous Mix Chemicals Friction Reducer (L/m3) 1.0 1 0 1 0 1.0 106.8 LFoaming Surfactant (L/m3) 3.0 3.0 3.0 0.0 307.4 L Pre-Mixed ChemicalsNONE

As per the treating program, proppant is begun by opening the proppantsupply valve (V2) initiating flow of proppant into the fracturingblender (14). In this example sand of varying mesh sizes is used;however any other natural or manmade proppant can be applied in the samemanner. The rate of proppant flow into the blender is controlled throughaugers, belts or sliding gates to achieve the correct proportion ofproppant in the liquid stream. In this fracture treatment programdesign, the fracturing blender (14) and high pressure slurry pump (16)rate remains constant so that the water rate is reduced by the rate ofthe added proppant. To maintain the foam quality and total foaminjection rate required, the natural gas rate is adjusted. In this caseto maintain the bottom hole rate, the liquid rate is reduced from 1.25m3/min to 1.22 m3/min and the natural gas rate is decreased from 1,170sm3/min to 1,143 sm3/min to account for the added proppant. Thetreatment program is continued with sand concentrations increasing withadjustment of the water and natural gas rates until sufficient proppanthas been pumped. If a screen out occurs, that being the proppant withinthe wellbore or the down hole fracture bridges to the degree such thatinjection is restricted and pressures increase beyond the allowablemaximum, all injection will be stopped and attempts to re-initiateinjection should not be considered. Once the proppant has been pumped,the well is flushed which displaces the proppant through the surfaceequipment, down the wellbore and into the underground fracture. The wellshould be flushed with the specified foam volume as calculated with anunderflush set at 0.5 m3 for this example. During flush, should theunderground fracturing pressure differ from that anticipated, the volumeof natural gas pumped within the flush will need to be adjusted for thechanged compressibility to ensure the correct flush volume is pumped.Upon flushing the well all equipment is shutdown, valve (V7) closed, theinstantaneous shut-in pressure recorded and all equipment and materialssources secured. All pressure in the treating lines conduit and pumpingequipment is released through to the conduit flare line (20) and thenatural gas containing equipment purged with nitrogen. The natural gasfracturing equipment is then rigged out. Note that the foam quality of75% presented in this example is only one possible value for foamquality and depending upon well requirements, foam qualities from under60% to over 95% can be used. Further, the amount of natural gas appliedor the foam quality used in the pad, to carry proppant or to flush thewell can be individually varied. Further, this treatment design is basedupon maintaining a constant blender rate. Proppant concentration canalso be changed by adjusting the blender rate while compensating withthe natural gas rate to generate a different foam quality but stillmaintain the same overall injection rate. In fact, proppant may not beemployed at all, as desired.

Following rigging out of the fracturing equipment and at a time deemedsuitable for the well being fractured, the well is flowed to clean upand evaluate. The natural gas foam is timed to break for the flow backsuch that the natural gas and water are no longer tightly intermingledin the form of stable foam. Rather, the water and natural gas are simplyand randomly commingled. Breaking of the foam can be achieved through anumber of methods, for example by degradation or removal of the foamingsurfactant. Degradation may include disassociation of the surfactantfoaming molecule by thermal breakdown or by chemical attack. Removal ofthe foaming surfactant from the liquid phase is typically achieved bysorption of the molecule onto solids such as the contacted reservoirrock. Breaking of the natural gas foam may also be accompanied by acontrolled reduction in viscosity of the liquid phase. Flow back of thewell following fracturing is accomplished by reducing the pressure atthe wellhead to permit the fracturing fluids to flow from the well,created fracture and reservoir, thereby opening a flow path for thereservoir oil and gas to flow. Within the reservoir, the reduction ofpressure allows the natural gas to expand and works to force the liquidphase of the fracture fluid from the reservoir and the fracture.Expansion of the natural gas also ensures a gas phase exists within thereservoir and created fractures. This gas phase provides permeability togas within the near reservoir area plus reduces the capillary pressuresholding the liquid phase in the reservoir matrix. A further benefit isachieved with solubility of the natural gas in the liquid phaseresulting in reduced surface tension. This mechanism can further reducecapillary pressure and improve relative permeability. Within thewellbore, reduction of pressure allows the natural gas to expand andfurther reduce the density of the commingled natural gas and liquidcolumn in the wellbore. This reduced density serves to enhance flow ofnatural gas and liquid up the wellbore reducing the bottom hole flowpressure. The reduced bottom hole pressure allows a higher differentialpressure between the reservoir and the wellbore permitting a higherdrawdown pressure to improve movement of the fracturing fluid from thereservoir and into the wellbore. The flow of the liquid phase out of thereservoir and created fractures is thereby enhanced ensuring a liquidblock does not occur.

The injected natural gas and fracturing fluid liquids released from thewell are diverted to the phase separator (60) where gases, liquids andsolids can be separated. Produced solids may include the fracturingproppant and are accumulated within the separator vessel (60) andremoved as needed for space considerations. Liquids are accumulatedwithin the separator (60) and drained into storage vessels, not shown.During the flow for clean-up and evaluation, injected and reservoirbased natural gas are directed from the separator vessel (60) to theflare stack (20) or preferentially diverted to the gas pipeline (21) forresale. The use of natural gas as the gas phase energizer permitsdiversion to the gas pipeline and fracture clean-up without the need toflare. Additionally, the use of natural gas permits immediate sale ofthe injected natural gas or reservoir based gas. As a furtherconsideration, the above example utilizes only approximately 110 m3(229,000 gallon) of water whereas placement of the same treatmentwithout energization would require in excess of 430 m3 (113,000 gallon)water. Replacement of a similar water volume with the conventional gasescarbon dioxide or nitrogen would require either significant flaring orscrubbing from produced gas prior to achieving a typical specificationfor gas sale. Foam quality can be increased beyond 75% to further reducewater consumption. These aspects reduce environmental impact and improveeconomics.

Comparable methods using the same approach as above is within otherembodiments and is applicable to other types of fracturing treatmentsand applications including energized and mist fracturing fluids; withand without proppants; with and without fracturing liquids such asacids, waters, brines, methanol, and hydrocarbons; and for use in allreservoir types including tight oil and gas, coal bed methane, shale oiland gas and conventional oil and gas recovery.

Various modifications to those embodiments will be readily apparent tothose skilled in the art. The present invention is not intended to belimited to the embodiments shown herein, but is to be accorded the fullscope consistent with the claims, wherein reference to an element in thesingular, such as by use of the article “a” or “an” is not intended tomean “one and only one” unless specifically so stated, but rather “oneor more”. All structural and functional equivalents to the elements ofthe various embodiments described throughout the disclosure that areknown or later come to be known to those of ordinary skill in the artare intended to be encompassed by the elements of the claims.

What is claimed is:
 1. A method of operating a formation fracturingsystem that uses a fracturing fluid comprising natural gas, the methodcomprising: (a) providing a formation fracturing system including anatural gas supply apparatus comprising a natural gas source, a pumpassembly for pressurizing natural gas from the natural gas source, andfluid supply conduits for transporting the natural gas from the naturalgas source to the pump assembly and to a wellhead of a well that is incommunication with an underground formation to be fractured; (b) forminga fracturing fluid by providing natural gas from the natural gas sourceand pressurizing the natural gas to a fracturing pressure of theformation using the pump assembly; (c) injecting the fracturing fluidthrough the wellhead and into the formation until the formation isfractured; and (d) injecting an inert fluid through at least part of theformation fracturing system before or after injecting the fracturingfluid through the wellhead and until the at least part of the formationfracturing system is purged to a non-flammable state.
 2. A method asclaimed in claim 1 wherein the inert fluid is injected before and afterthe fracturing fluid is injected into the wellhead.
 3. A method asclaimed in claim 1 wherein the method further comprises after injectingthe inert fluid through the at least part of the formation fracturingsystem, directing the injected inert fluid into the well.
 4. A method asclaimed in claim 3 wherein the method further comprises directing theinjected inert fluid into the well until the inert fluid contributes tofracturing the formation.
 5. A method as claimed in claim 1 wherein themethod further comprises after injecting the inert fluid through the atleast part of the formation fracturing system, venting the injectedinert fluid.
 6. A method as claimed in claim 4 further comprising afterdirecting the injected inert fluid into the well, injecting natural gasthrough the system such that inert fluid in the system is displaced intothe well.
 7. A method as claimed in claim 1 wherein the natural gassource is liquefied natural gas, the natural gas supply apparatusincludes a heater for heating the liquefied natural gas to anapplication temperature, and the method further comprises injecting acryogenic inert fluid before the fracturing fluid is injected into atleast part of the formation fracturing system to pre-cool the at leastpart of the formation fracturing system prior to natural gas injection.8. A method as claimed in claim 7 wherein the cryogenic inert fluid isliquefied nitrogen.
 9. A method as claimed in claim 1 wherein theformation fracturing system further comprises valves coupled to thefluid supply conduits, and the method further comprises closing at leastsome of the valves to fluidly isolate at least part of the formationfracturing system, then injecting the inert fluid into the isolated partof the system and pressure testing the isolated part of the system. 10.A method as claimed in claim 1 wherein the formation fracturing systemfurther comprises valves coupled to the fluid supply conduits and aventing conduit fluidly coupled to at least part of the natural gassupply apparatus, and the method further comprises after natural gas hasbeen injected into the wellhead: closing at least some of the valves toisolate at least part of the natural gas supply apparatus from the restof the formation fracturing system, opening at least some of the valvesto vent natural gas from the isolated part of the natural gas supplyapparatus and out of the system via the venting conduit, then injectingthe inert fluid into the isolated part of the natural gas supplyapparatus for purging thereof.
 11. A method as claimed in any of claims1 to 10 wherein the system further comprises: a base fluid supplyapparatus and a mixer fluid coupled to the base fluid supply apparatusand natural gas supply apparatus and to the wellhead, and the methodfurther comprises forming a fracturing fluid mixture comprising a basefluid from the base fluid supply apparatus and the natural gas in themixer, then injecting the fracturing fluid mixture into the wellheaduntil the formation is fractured.
 12. A method as claimed in claim 11wherein the method further comprises before injecting natural gas intothe wellhead, injecting the inert fluid through the natural gas supplyapparatus and mixer until they are purged to a non-flammable state. 13.A method as claimed in claims 10 and 11 wherein the venting conduit isfurther coupled to at least part of the base fluid supply apparatus andthe mixer, and the method further comprises after natural gas has beeninjected into the wellhead: isolating at least part of the base fluidsupply apparatus or mixer or both, then injecting the inert fluidtherethrough and out of the system via the venting conduit.
 14. A methodas claimed in any of claims 1 to 13 wherein the inert fluid is selectedfrom the group consisting of nitrogen, helium, neon, argon, kyrpton andcarbon dioxide or mixtures thereof.
 15. A system for fracturing adownhole formation, comprising: (a) a natural gas supply apparatuscomprising a natural gas source, a pump assembly for pressurizingnatural gas from the natural gas source to a fracturing pressure of adownhole formation, and natural gas fluid supply conduits fluidlycoupling the natural gas source to the pump assembly and to a wellheadof a well that is in communication with the downhole formation; (b) aninert fluid supply apparatus comprising an inert fluid source and inertfluid supply conduits fluidly coupling the inert fluid source to atleast part of the natural gas supply apparatus; (c) a venting conduitfluidly coupled to at least part of the natural gas supply apparatussuch that natural gas and inert fluid can be vented from the system; and(d) valves coupled to at least the natural gas and inert fluid supplyconduits that can be selectively opened and closed to inject the naturalgas through the wellhead until a formation is fractured, and to injectthe inert fluid through at least part of the natural gas supplyapparatus for purging thereof either before or after the natural gas isinjected into the wellhead.
 16. A system as claimed in claim 15 whereinthe inert fluid supply apparatus further comprises a pump for moving theinert fluid through and out of the at least part of the natural gassupply apparatus.
 17. A system as claimed in claim 15 wherein the inertfluid supply apparatus further comprises a nitrogen source or a carbondioxide source.
 18. A system as claimed in claim 15 further comprising abase fluid supply apparatus and a mixer fluidly coupled to the basefluid supply apparatus, natural gas supply apparatus and to thewellhead.
 19. A system as claimed in claim 18 wherein the base fluidsupply apparatus comprises a base fluid source, a base fluid pump andbase fluid supply conduits for fluidly coupling the base fluid source tothe base fluid pump and to the mixer.
 20. A system as claimed in claim19 wherein the base fluid supply apparatus further comprises a proppantsupply and a blender fluidly coupled to the proppant supply and the basefluid source and the base fluid pump.
 21. A system as claimed in claim19 wherein the base fluid supply apparatus further comprises a chemicalsource and a blender fluidly coupled to the chemical source and the basefluid source and the base fluid pump.
 22. A system as claimed in claim19 wherein the base fluid supply apparatus further comprises a chemicalsource, a proppant supply, and a blender fluidly coupled to the proppantsupply, chemical source, base fluid source, and the base fluid pump. 23.A system as claimed in claims 21 or 22 wherein the chemical source is aviscosifier source.
 24. A system as claimed in any of claims 14 to 23further comprising a system flare coupled to the venting conduit.